Constellation Energy Corp 10-K

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Management’s Report on Internal Control Over Financial Reporting We are responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. We assessed the effectiveness of our internal control over financial reporting as of December 31, 2021. In making this assessment, we used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, we concluded that, as of December 31, 2021, our internal control over financial reporting was effective. February 25, 2022 79 Table of Contents Report of Independent Registered Public Accounting Firm To the Board of Directors and Member of Constellation Energy Generation, LLC Opinion on the Financial Statements We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(ii), of Constellation Energy Generation, LLC (formerly known as Exelon Generation Company, LLC) and its subsidiaries (the “Company”) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021 in conformity with accounting principles generally accepted in the United States of America. Basis for Opinion These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion. Critical Audit Matters The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that (i) relate to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate. Annual Nuclear Decommissioning Asset Retirement Obligations (AROs) Assessment As described in Notes 1 and 10 to the consolidated financial statements, the Company has a legal obligation to decommission its nuclear generation stations following permanent cessation of operations. To estimate its decommissioning obligations related to its nuclear generating stations for financial accounting and reporting purposes, management uses a probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models, and discount rates. Management updates its AROs annually, unless circumstances warrant more frequent updates, based on its review of updated cost studies and its annual evaluation of cost escalation factors and probabilities assigned to various scenarios. As of December 31, 2021, the nuclear decommissioning AROs were $12.7 billion. 80 Table of Contents The principal considerations for our determination that performing procedures relating to the Company’s annual nuclear decommissioning AROs assessment is a critical audit matter are the significant judgment by management when estimating its decommissioning obligations; this in turn led to a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating the reasonableness of management’s discounted cash flow model and significant assumptions related to decommissioning cost studies. In addition, the audit effort involved the use of professionals with specialized skill and knowledge. Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s development of the inputs, assumptions, and model used in management’s AROs assessment. These procedures also included, among others, testing management’s process for estimating the decommissioning obligations by evaluating the appropriateness of the discounted cash flow model, testing the completeness and accuracy of data used by management, and evaluating the reasonableness of management’s significant assumptions related to decommissioning cost studies. Professionals with specialized skill and knowledge were used to assist in evaluating the results of decommissioning cost studies. Impairment Assessment of Long-Lived Generation Assets As described in Notes 1, 8, and 12 to the consolidated financial statements, the Company evaluates the carrying value of long-lived assets or asset groups for recoverability whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators of impairment may include a deteriorating business climate, including, but not limited to, declines in energy prices, condition of the asset, or plans to dispose of a long-lived asset significantly before the end of its useful life. Management determines if long-lived assets or asset groups are potentially impaired by comparing the undiscounted expected future cash flows to the carrying value when indicators of impairment exist. When the undiscounted cash flow analysis indicates a long-lived asset or asset group may not be recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value. The fair value analysis is primarily based on the income approach using significant unobservable inputs including revenue and generation forecasts, projected capital and maintenance expenditures, and discount rates. As of December 31, 2021, the total carrying value of long-lived generation assets subject to this assessment was $19.6 billion. The principal considerations for our determination that performing procedures relating to the Company’s impairment assessment of long-lived generation assets is a critical audit matter are the significant judgment by management in assessing the recoverability and estimating the fair value of these long-lived generation assets or asset groups; this in turn led to a high degree of auditor judgment, subjectivity and effort in performing procedures and evaluating the reasonableness of management’s significant assumptions related to revenue and generation forecasts. In addition, the audit effort involved the use of professionals with specialized skill and knowledge. Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s development of the inputs, assumptions, and model used to assess the recoverability and estimate the fair value of the Company’s long-lived generation assets or asset groups. These procedures also included, among others, testing management’s process for developing the expected future cash flows for the long-lived generation assets or asset groups by evaluating the appropriateness of the future cash flow model, testing the completeness and accuracy of the data used by management, and evaluating the reasonableness of management’s significant assumptions related to revenue and generation forecasts. Evaluating the reasonableness of the revenue and generation forecasts involved considering whether the forecasts were consistent with future commodity prices and external market data. Professionals with specialized skill and knowledge were used to assist in evaluating the reasonableness of the revenue forecasts. /s/ PricewaterhouseCoopers LLP Baltimore, Maryland February 25, 2022 We have served as the Company's auditor since 2001. 81 Table of Contents Constellation Energy Generation, LLC and Subsidiary Companies Consolidated Statements of Operations and Comprehensive Income For the Years Ended December 31, (In millions) 2021 2020 2019 Operating revenues Operating revenues $ 18,461 $ 16,392 $ 17,752 Operating revenues from affiliates 1,188 1,211 1,172 Total operating revenues 19,649 17,603 18,924 Operating expenses Purchased power and fuel 12,157 9,592 10,849 Purchased power and fuel from affiliates 6 ( 7 ) 7 Operating and maintenance 3,934 4,613 4,131 Operating and maintenance from affiliates 621 555 587 Depreciation and amortization 3,003 2,123 1,535 Taxes other than income taxes 475 482 519 Total operating expenses 20,196 17,358 17,628 Gain on sales of assets and businesses 201 11 27 Operating (loss) income ( 346 ) 256 1,323 Other income and (deductions) Interest expense, net ( 282 ) ( 328 ) ( 394 ) Interest expense to affiliates ( 15 ) ( 29 ) ( 35 ) Other, net 795 937 1,023 Total other income and (deductions) 498 580 594 Income before income taxes 152 836 1,917 Income taxes 225 249 516 Equity in losses of unconsolidated affiliates ( 10 ) ( 8 ) ( 184 ) Net (loss) income ( 83 ) 579 1,217 Net income (loss) attributable to noncontrolling interests 122 ( 10 ) 92 Net (loss) income attributable to membership interest $ ( 205 ) $ 589 $ 1,125 Comprehensive (loss) income, net of income taxes Net (loss) income $ ( 83 ) $ 579 $ 1,217 Other comprehensive (loss) income, net of income taxes Unrealized loss on cash flow hedges ( 1 ) ( 2 ) — Unrealized gain on investments in unconsolidated affiliates — — 1 Unrealized gain on foreign currency translation — 4 6 Other comprehensive (loss) income, net of income taxes ( 1 ) 2 7 Comprehensive (loss) income ( 84 ) 581 1,224 Comprehensive income (loss) attributable to noncontrolling interests 122 ( 10 ) 93 Comprehensive (loss) income attributable to membership interest $ ( 206 ) $ 591 $ 1,131 82 Table of Contents Constellation Energy Generation, LLC and Subsidiary Companies Consolidated Statements of Cash Flows For the Years Ended December 31, (In millions) 2021 2020 2019 Cash flows from operating activities Net (loss) income $ ( 83 ) $ 579 $ 1,217 Adjustments to reconcile net (loss) income to net cash flows provided by operating activities: Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization 4,540 3,636 3,063 Asset impairments 545 563 201 Gain on sales of assets and businesses ( 201 ) ( 11 ) ( 27 ) Deferred income taxes and amortization of investment tax credits ( 205 ) 78 361 Net fair value changes related to derivatives ( 568 ) ( 270 ) 228 Net realized and unrealized gains on NDT funds ( 586 ) ( 461 ) ( 663 ) Net unrealized (losses) gains on equity investments 160 ( 186 ) — Other non-cash operating activities ( 605 ) 18 ( 124 ) Changes in assets and liabilities: Accounts receivable ( 616 ) 1,125 ( 186 ) Receivables from and payables to affiliates, net 14 24 ( 52 ) Inventories ( 68 ) ( 77 ) ( 47 ) Accounts payable and accrued expenses 346 ( 343 ) ( 248 ) Option premiums paid, net ( 338 ) ( 139 ) ( 29 ) Collateral (posted) received , net ( 130 ) 479 ( 481 ) Income taxes 256 186 302 Pension and non-pension postretirement benefit contributions ( 259 ) ( 255 ) ( 175 ) Other assets and liabilities ( 3,540 ) ( 4,362 ) ( 467 ) Net cash flows (used in) provided by operating activities ( 1,338 ) 584 2,873 Cash flows from investing activities Capital expenditures ( 1,329 ) ( 1,747 ) ( 1,845 ) Proceeds from NDT fund sales 6,532 3,341 10,051 Investment in NDT funds ( 6,673 ) ( 3,464 ) ( 10,087 ) Collection of DPP 3,902 3,771 — Proceeds from sales of assets and businesses 878 46 52 Acquisitions of assets and businesses, net — — ( 41 ) Other investing activities ( 28 ) 11 3 Net cash flows provided by (used in) investing activities 3,282 1,958 ( 1,867 ) Cash flows from financing activities Changes in short-term borrowings 362 20 320 Proceeds from short-term borrowings with maturities greater than 90 days 880 500 — Issuance of long-term debt 152 3,155 42 Retirement of long-term debt ( 105 ) ( 4,334 ) ( 813 ) Retirement of long-term debt to affiliate — ( 550 ) — Changes in money pool with Exelon ( 285 ) 285 ( 100 ) Acquisition of CENG noncontrolling interest ( 885 ) — — Distributions to member ( 1,832 ) ( 1,734 ) ( 899 ) Contributions from member 64 64 41 Other financing activities ( 46 ) ( 70 ) ( 51 ) Net cash flows used in financing activities ( 1,695 ) ( 2,664 ) ( 1,460 ) Increase (decrease) in cash, restricted cash, and cash equivalents 249 ( 122 ) ( 454 ) Cash, restricted cash, and cash equivalents at beginning of period 327 449 903 Cash, restricted cash, and cash equivalents at end of period $ 576 $ 327 $ 449 Supplemental cash flow information Increase (decrease) in capital expenditures not paid $ 96 $ ( 88 ) $ ( 34 ) Increase in DPP 3,652 4,441 — Increase in PP&E related to ARO update 618 850 959 See the Notes to Consolidated Financial Statements 83 Table of Contents Constellation Energy Generation, LLC and Subsidiary Companies Consolidated Balance Sheets December 31, (In millions) 2021 2020 ASSETS Current assets Cash and cash equivalents $ 504 $ 226 Restricted cash and cash equivalents 72 89 Accounts receivable Customer accounts receivable 1,724 1,330 Customer allowance for credit losses ( 55 ) ( 32 ) Customer accounts receivable, net 1,669 1,298 Other accounts receivable 597 352 Other allowance for credit losses ( 5 ) — Other accounts receivable, net 592 352 Mark-to-market derivative assets 2,169 644 Receivables from affiliates 160 153 Inventories, net Fossil fuel and emission allowances 284 233 Materials and supplies 1,004 978 Renewable energy credits 520 621 Assets held for sale 13 958 Other 994 1,395 Total current assets 7,981 6,947 Property, plant, and equipment (net of accumulated depreciation and amortization of $ 15,873 and $ 13,370 as of December 31, 2021 and 2020, respectively) 19,612 22,214 Deferred debits and other assets Nuclear decommissioning trust funds 15,938 14,464 Investments 174 184 Mark-to-market derivative assets 949 555 Prepaid pension asset 1,683 1,558 Deferred income taxes 32 6 Other 1,717 2,166 Total deferred debits and other assets 20,493 18,933 Total assets (a) $ 48,086 $ 48,094 See the Notes to Consolidated Financial Statements 84 Table of Contents Constellation Energy Generation, LLC and Subsidiary Companies Consolidated Balance Sheets December 31, (In millions) 2021 2020 LIABILITIES AND EQUITY Current liabilities Short-term borrowings $ 2,082 $ 840 Long-term debt due within one year 1,220 197 Accounts payable 1,757 1,253 Accrued expenses 737 788 Payables to affiliates 131 107 Borrowings from money pool with Exelon — 285 Mark-to-market derivative liabilities 981 262 Renewable energy credit obligation 777 661 Liabilities held for sale 3 375 Other 308 451 Total current liabilities 7,996 5,219 Long-term debt 4,575 5,566 Long-term debt to affiliates 319 324 Deferred credits and other liabilities Deferred income taxes and unamortized investment tax credits 3,703 3,656 Asset retirement obligations 12,819 12,054 Non-pension postretirement benefit obligations 847 858 Spent nuclear fuel obligation 1,210 1,208 Payables to affiliates 3,357 3,017 Mark-to-market derivative liabilities 513 205 Other 1,133 1,311 Total deferred credits and other liabilities 23,582 22,309 Total liabilities (a) 36,472 33,418 Commitments and contingencies Equity Member’s equity Membership interest 10,482 9,624 Undistributed earnings 768 2,805 Accumulated other comprehensive loss, net ( 31 ) ( 30 ) Total member’s equity 11,219 12,399 Noncontrolling interests 395 2,277 Total equity 11,614 14,676 Total liabilities and equity $ 48,086 $ 48,094 __________ (a) Our consolidated assets include $ 2,549 million and $ 10,182 million as of December 31, 2021 and 2020, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Our consolidated liabilities include $ 1,077 million and $ 3,572 million as of December 31, 2021 and 2020, respectively, of certain VIEs for which the VIE creditors do not have recourse to us. See Note 21–Variable Interest Entities for additional information. See the Notes to Consolidated Financial Statements 85 Table of Contents Constellation Energy Generation, LLC and Subsidiary Companies Consolidated Statements of Changes in Equity Member’s Equity Noncontrolling Interests Total Equity (In millions) Membership Interest Undistributed Earnings Accumulated Other Comprehensive Loss, net Balance, December 31, 2018 $ 9,518 $ 3,724 $ ( 38 ) $ 2,304 $ 15,508 Net income — 1,125 — 92 1,217 Sale of noncontrolling interests 7 — — — 7 Changes in equity of noncontrolling interests — — — ( 48 ) ( 48 ) Distributions to member — ( 899 ) — — ( 899 ) Contributions from member 41 — — — 41 Other comprehensive income (loss), net of income taxes — — 6 ( 2 ) 4 Balance, December 31, 2019 $ 9,566 $ 3,950 $ ( 32 ) $ 2,346 $ 15,830 Net income (loss) — 589 — ( 10 ) 579 Sale of noncontrolling interests 3 — — — 3 Changes in equity of noncontrolling interests — — — ( 59 ) ( 59 ) Distribution to member of deferred taxes associated with net retirement benefit obligation ( 9 ) — — — ( 9 ) Distributions to member — ( 1,734 ) — — ( 1,734 ) Contributions from member 64 — — — 64 Other comprehensive income, net of income taxes — — 2 — 2 Balance, December 31, 2020 $ 9,624 $ 2,805 $ ( 30 ) $ 2,277 $ 14,676 Net (loss) income — ( 205 ) — 122 ( 83 ) Changes in equity of noncontrolling interests — — — ( 37 ) ( 37 ) Acquisition of CENG noncontrolling interest 1,080 — — ( 1,965 ) ( 885 ) Deferred tax adjustment related to acquisition of CENG noncontrolling interest ( 288 ) — — — ( 288 ) Distributions to member — ( 1,832 ) — — ( 1,832 ) Contributions from member 64 — — — 64 Acquisition of other noncontrolling interest 2 — — ( 2 ) — Other comprehensive loss, net of income taxes — — ( 1 ) — ( 1 ) Balance, December 31, 2021 $ 10,482 $ 768 $ ( 31 ) $ 395 $ 11,614 See the Notes to Consolidated Financial Statements 86 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) 1. Significant Accounting Policies Description of Business We are a supplier of clean energy. Our generating capacity consists of nuclear, wind, solar, natural gas and hydroelectric assets. Through our integrated business operations, we sell electricity, natural gas, and other energy related products and sustainable solutions to various types of customers, including distribution utilities, municipalities, cooperatives, and commercial, industrial, governmental, and residential customers in competitive markets across multiple geographic regions. We have five reportable segments: Mid-Atlantic, Midwest, New York, ERCOT and Other Power Regions. Basis of Presentation On February 21, 2021, the board of directors of Exelon authorized management to pursue a plan to separate its competitive generation and customer-facing energy businesses, conducted through Constellation Energy Generation, LLC ( “ Constellation ” , formerly Exelon Generation Company, LLC) and its subsidiaries, into an independent, publicly-traded company. CEG Parent, a direct, wholly owned subsidiary of Exelon, was newly formed for the purpose of separation and had not engaged in any business activities nor had any assets or liabilities prior to the separation. On February 1, 2022, Exelon completed the separation by distributing all the outstanding shares of CEG Parent’s common stock, on a pro rata basis to the holders of Exelon’s common stock, with CEG Parent holding all the interests in Constellation previously held by Exelon. See Note 24 — Separation from Exelon for additional information. As an individual registrant, Constellation has historically filed consolidated financial statements to reflect its financial position and operating results as a stand-alone, wholly owned subsidiary of Exelon. The accompanying Consolidated Financial Statements of Constellation have been prepared in accordance with GAAP for annual financial statements and in accordance with the instructions to Form 10-K and Regulation S-X promulgated by the SEC. The Consolidated Financial Statements include the accounts of our subsidiaries and all intercompany transactions have been eliminated. Unless otherwise indicated or the context otherwise requires, references herein to the terms “we,” “us,” and “our” refer to Constellation. We own 100 % of our significant consolidated subsidiaries, either directly or indirectly, except for certain consolidated VIEs, including CRP, of which we hold a 51 % interest. The remaining interests in the consolidated VIEs are included in noncontrolling interests on the Consolidated Balance Sheets. See Note 21 — Variable Interest Entities for additional information on consolidated VIEs. We consolidate the accounts of entities in which we have a controlling financial interest, after the elimination of intercompany transactions. Where we do not have a controlling financial interest in an entity, proportionate consolidation, equity method accounting or accounting for investments in equity securities with or without readily determinable fair value is applied. We apply proportionate consolidation when we have an undivided interest in an asset and are proportionately liable for our share of each liability associated with the asset. We proportionately consolidate our undivided ownership interest in jointly owned electric plants. Under proportionate consolidation, we separately record our proportionate share of the assets, liabilities, revenues and expenses related to the undivided interest in the asset. We apply equity method accounting when we have a significant influence over an investee through an ownership in equity, which generally approximates a 20 % to 50 % voting interest. We apply equity method accounting to certain investments and joint ventures. Under equity method accounting, we report our interest in the entity as an investment and our percentage share of the earnings from the entity as single line items in our financial statements. We use accounting for investments in equity securities with or without readily determinable fair values if we lack a significant influence, which generally results when we hold less than 20 % of the common stock of an entity. Under accounting for investments in equity securities with readily determinable fair values, the investments are reported based on quoted prices in active markets and realized and unrealized gains and losses are included in earnings. Under accounting for investments in equity securities without readily determinable fair values, the investments are reported at cost adjusted for changes from observable transactions for identical or similar investments of the same issuer, less impairment, and changes in measurement are reported in earnings. 87 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 1 — Significant Accounting Policies COVID-19 We have taken steps to mitigate the potential risks posed by the global outbreak (pandemic) of the 2019 novel coronavirus (COVID-19). We provide a critical service to our customers and have taken measures to keep employees who operate the business safe and minimize unnecessary risk of exposure to the virus, including extra precautions for employees who work in the field. We have implemented work from home policies where appropriate and imposed travel limitations on employees. Management makes estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and accompanying notes, and the amounts of revenues and expenses reported during the periods covered by those financial statements and accompanying notes. As of December 31, 2021 and 2020, and through the date of this report, management assessed certain accounting matters that require consideration of forecasted financial information, including, but not limited to the allowance for credit losses and the carrying value of other long-lived assets, in context with the information reasonably available to us and the unknown future impacts of COVID-19. Our future assessment of the magnitude and duration of COVID-19, as well as other factors, could result in material impacts in the consolidated financial statements in future reporting periods. Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Areas in which significant estimates have been made include, but are not limited to, the accounting for nuclear decommissioning costs and other AROs, pension and OPEB plans, inventory reserves, allowance for credit losses, long-lived asset impairment assessments, derivative instruments, unamortized energy contracts, fixed asset depreciation, environmental costs and other loss contingencies, taxes and unbilled energy revenues. Actual results could differ from those estimates. Revenues Operating Revenues. Our operating revenues generally consist of revenues from contracts with customers involving the sale and delivery of energy commodities and related products and services and realized and unrealized revenues recognized under mark-to-market energy commodity derivative contracts. We recognize revenue from contracts with customers to depict the transfer of goods or services to customers in an amount that we expect to be entitled to in exchange for those goods or services. Our primary source of revenue includes competitive sales of power, natural gas, and other energy-related products and services. At the end of each reporting period, we accrue an estimate for the unbilled amount of energy delivered or services provided to customers. Option Contracts, Swaps and Commodity Derivatives. Certain option contracts and swap arrangements that meet the definition of derivative instruments are recorded at fair value with subsequent changes in fair value recognized as revenue or expense. The classification of revenue or expense is based on the intent of the transaction. See Note 16 — Derivative Financial Instruments for additional information. Taxes Directly Imposed on Revenue-Producing Transactions. We collect certain taxes from customers such as sales and gross receipts taxes, along with other taxes, surcharges and fees, that are levied by state or local governments on the sale or distribution of electricity and natural gas. Some of these taxes are imposed on the customer, but paid by us, while others are imposed on us. Where these taxes are imposed on the customer, such as sales taxes, they are reported on a net basis with no impact to the Consolidated Statements of Operations and Comprehensive Income. However, where these taxes are imposed on us, such as gross receipts taxes, they are reported on a gross basis. Accordingly, revenues are recognized for the taxes collected from customers along with an offsetting expense. Se e Note 22 — Supplemental Financial Information for the taxes that are presented on a gross basis. Leases We recognize a ROU asset and lease liability for operating leases with a term of greater than one year. Operating lease ROU assets are included in Other deferred debits and other assets and operating lease liabilities are included in Other current liabilities and Other deferred credits and other liabilities on the Consolidated 88 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 1 — Significant Accounting Policies Balance Sheets. The ROU asset is measured as the sum of (1) the present value of all remaining fixed and in-substance fixed payments using the rate implicit in the lease whenever that is readily determinable or our incremental borrowing rate, (2) any lease payments made at or before the commencement date (less any lease incentives received) and (3) any initial direct costs incurred. The lease liability is measured the same as the ROU asset, but excludes any payments made before the commencement date and initial direct costs incurred. Lease terms include options to extend or terminate the lease if it is reasonably certain they will be exercised. We include non-lease components for most asset classes, which are service-related costs that are not integral to the use of the asset, in the measurement of the ROU asset and lease liability. Expense for operating leases and leases with a term of one year or less is recognized on a straight-line basis over the term of the lease, unless another systematic and rational basis is more representative of the derivation of benefit from use of the leased property. Variable lease payments are recognized in the period in which the related obligation is incurred and consist primarily of payments for purchases of electricity under contracted generation that are based on the electricity produced by those generating assets. Operating lease expense and variable lease payments are recorded to Purchased power and fuel expense for contracted generation or Operating and maintenance expense for all other lease agreements in the Consolidated Statements of Operations and Comprehensive Income. Income from operating leases, including subleases, is recognized on a straight-line basis over the term of the lease, unless another systematic and rational basis is more representative of the pattern in which income is earned over the term of the lease. Variable lease payments are recognized in the period in which the related obligation is performed and consist primarily of payments received from sales of electricity under contracted generation that are based on the electricity produced by those generating assets. Operating lease income and variable lease payments are recorded to Operating revenues in the Consolidated Statements of Operations and Comprehensive Income. Our operating leases consist primarily of contracted generation, real estate including office buildings, and vehicles and equipment. We generally account for contracted generation in which the generating asset is not renewable as a lease if the customer has dispatch rights and obtains substantially all the economic benefits. We generally do not account for contracted generation in which the generating asset is renewable as a lease if the customer does not design the generating asset. We account for land right arrangements that provide for exclusive use as leases while shared use land arrangements are generally not leases. See Note 11 — Leases for additional information. Income Taxes Deferred federal and state income taxes are recorded on significant temporary differences between the book and tax basis of assets and liabilities and for tax benefits carried forward. Investment tax credits have been deferred in the Consolidated Balance Sheets and are recognized in book income over the life of the related property. We account for uncertain income tax positions using a benefit recognition model with a two-step approach; a more-likely-than-not recognition criterion; and a measurement approach that measures the position as the largest amount of tax benefit that is greater than 50 % likely of being realized upon ultimate settlement. If it is not more-likely-than-not that the benefit of the tax position will be sustained on its technical merits, no benefit is recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. We recognize accrued interest related to unrecognized tax benefits in Interest expense, net or Other, net (interest income) and recognize penalties related to unrecognized tax benefits in Other, net in the Consolidated Statements of Operations and Comprehensive Income. Cash and Cash Equivalents We consider investments purchased with an original maturity of three months or less to be cash equivalents. Restricted Cash and Cash Equivalents 89 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 1 — Significant Accounting Policies Restricted cash and cash equivalents represent funds that are restricted to satisfy designated current liabilities. As of December 31, 2021 and 2020, restricted cash and cash equivalents primarily represented the project-specific nonrecourse financing structures for debt service and financing of operations of the underlying entities. See Note 17 — Debt and Credit Agreements and Note 22 — Supplemental Financial Information for additional information. Allowance for Credit Losses on Accounts Receivables The allowance for credit losses reflects our best estimate of losses on the customers' accounts receivable balances based on historical experience, current information, and reasonable and supportable forecasts. The allowance for credit losses for our retail customers is based on accounts receivable aging historical experience coupled with specific identification through a credit monitoring process, which considers current conditions and forward-looking information such as industry trends, macroeconomic factors, changes in the regulatory environment, external credit ratings, publicly available news, payment status, payment history, and the exercise of collateral calls. The allowance for credit losses for our wholesale customers is developed using a credit monitoring process, like that used for retail customers. When a wholesale customer’s risk characteristics are no longer aligned with the pooled population, we use specific identification to develop an allowance for credit losses. Adjustments to the allowance for credit losses are recorded in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. We have certain non-customer receivables in Other deferred debits and other assets which primarily are with governmental agencies and other high-quality counterparties with no history of default. As such, the allowance for credit losses related to these receivables is not material. We monitor these balances and will record an allowance if there are indicators of a decline in credit quality. Variable Interest Entities We account for our investments in and arrangements with VIEs based on the following specific requirements: • qualitative assessment of factors determinant in whether we have a controlling financial interest, • ongoing reconsideration of this assessment, and • where we consolidate a VIE (as primary beneficiary), disclosure of (1) the assets of the consolidated VIE, if they can be used to only settle specific obligations of the consolidated VIE, and (2) the liabilities of a consolidated VIE for which creditors do not have recourse to the general credit of the primary beneficiary. See Note 21 — Variable Interest Entities for additional information. Inventories Inventory is recorded at the lower of weighted average cost or net realizable value. Provisions are recorded for excess and obsolete inventory. Natural gas, oil, materials and supplies, and emissions allowances are generally included in inventory when purchased. Natural gas, oil, and emissions allowances are expensed to Purchased power and fuel expense when used or sold. Materials and supplies generally include items utilized within our generating plants and are expensed to Operating and maintenance or capitalized to Property, plant and equipment, as appropriate, when installed or used. Debt and Equity Security Investments Debt Security Investments. Debt securities are reported at fair value and classified as available-for-sale securities. Unrealized gains and losses, net of tax, are reported in Other Comprehensive Income. Equity Security Investments without Readily Determinable Fair Values. We have certain equity securities without readily determinable fair values. We have elected to use the measurement alternative to measure these investments, defined as cost adjusted for changes from observable transactions for identical or similar investments of the same issuer, less impairment. Changes in measurement are reported in Other, net in the Consolidated Statements of Operations and Comprehensive Income. 90 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 1 — Significant Accounting Policies Equity Security Investments with Readily Determinable Fair Values. We have certain equity securities with readily determinable fair values. For equity securities held in NDT funds, realized and unrealized gains and losses, net of tax, on our NDT funds associated with the Regulatory Agreement Units are included in Noncurrent payables to affiliates. Realized and unrealized gains and losses, net of tax, on our NDT funds associated with the Non-Regulatory Agreement Units are included in earnings. Our NDT funds are classified as current or noncurrent assets, depending on the timing of the decommissioning activities and income taxes on trust earnings. For all other equity securities with readily determinable fair values, realized and unrealized gains and losses are included in Other, net in the Consolidated Statements of Operations and Comprehensive Income. See Note 18 — Fair Value of Financial Assets and Liabilities and Note 10 — Asset Retirement Obligations for additional information. Property, Plant and Equipment Property, plant and equipment is recorded at original cost. Original cost includes construction-related direct labor and material costs. When appropriate, original cost also includes capitalized interest. Costs associated with nuclear outages and planned major maintenance activities, are expensed to Operating and maintenance expense or capitalized to Property, plant, and equipment based on the nature of the activities in the period incurred. The cost of repairs and maintenance and minor replacements of property, is charged to Operating and maintenance expense as incurred. Upon retirement, the cost of property is generally charged to accumulated depreciation in accordance with the composite and group methods of depreciation. Upon replacement of an asset, the costs to remove the asset, net of salvage, are capitalized to gross plant when incurred as part of the cost of the newly-installed asset and recorded to depreciation expense over the life of the new asset. Removal costs, net of salvage, incurred for property that will not be replaced is charged to Operating and maintenance expense as incurred. Capitalized Software. Certain costs, such as design, coding, and testing incurred during the application development stage of software projects that are internally developed or purchased for operational use are capitalized in Property, plant and equipment in the Consolidated Balance Sheets. Similar costs incurred for cloud-based solutions treated as service arrangements are capitalized in Other current assets and Deferred debits and other assets in the Consolidated Balance Sheets. Such capitalized amounts are amortized ratably over the expected lives of the projects when they become operational, generally not to exceed five years. Certain other capitalized software costs are being amortized over longer lives based on the expected life. Capitalized Interest. During construction, we capitalize the costs of debt funds used to finance construction projects. Capitalization of debt funds is recorded as a charge to construction work in progress and as a non-cash credit to interest expense. See Note 8 — Property, Plant, and Equipment, Note 9 — Jointly Owned Electric Utility Plant and Note 22 — Supplemental Financial Information for additional information. Nuclear Fuel The cost of nuclear fuel is capitalized in Property, plant and equipment and charged to Purchased power and fuel using the unit-of-production method. Any potential future SNF disposal fees will also be expensed through Purchased power and fuel expense. Additionally, certain on-site SNF storage costs are being reimbursed by the DOE since a DOE (or government-owned) long-term storage facility has not been completed. See Note 19 — Commitments and Contingencies for additional information regarding the cost of SNF storage and disposal. Depreciation and Amortization Except for the amortization of nuclear fuel, depreciation is generally recorded over the estimated service lives of property, plant and equipment on a straight-line basis using the group, composite or unitary methods of depreciation. The group approach is typically for groups of similar assets that have approximately the same useful lives and the composite approach is used for dissimilar assets that have different lives. Under both methods, a reporting entity depreciates the assets over the average life of the assets in the group. The estimated service lives are based on a combination of depreciation studies, historical retirements, site licenses and management estimates of operating costs and expected future energy market conditions. See Note 7 — Early Plant Retirements for additional information on the impacts of early plant retirements, Note 8 — Property, Plant, and Equipment for additional information regarding depreciation, and Note 22 — Supplemental Financial Information for additional information regarding nuclear fuel and ARC. 91 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 1 — Significant Accounting Policies Asset Retirement Obligations We estimate and recognize a liability for our legal obligation to perform asset retirement activities even though the timing and/or methods of settlement may be conditional on future events. We generally update our nuclear decommissioning ARO annually, unless circumstances warrant more frequent updates, based on our annual evaluation of cost escalation factors and probabilities assigned to the multiple outcome scenarios within our probability-weighted discounted cash flow models. Our multiple outcome scenarios are generally based on decommissioning cost studies which are updated, on a rotational basis, for each of our nuclear units at least every five years, unless circumstances warrant more frequent updates. AROs are accreted throughout each year to reflect the time value of money for these present value obligations through a charge to Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income for Non-Regulatory Agreement Units and through a decrease in noncurrent payables to affiliates for Regulatory Agreement Units. See Note 10 — Asset Retirement Obligations for additional information. Guarantees If necessary, we recognize a liability at the time of issuance of a guarantee for the fair value of the obligations we have undertaken by issuing the guarantee. The liability is reduced or eliminated as we are released from risk under the guarantee. Depending on the nature of the guarantee, the release from risk may be recognized only upon the expiration or settlement of the guarantee or by a systematic and rational amortization method over the term of the guarantee. See Note 19 — Commitments and Contingencies for additional information. Asset Impairments Long-Lived Assets. We regularly monitor and evaluate the carrying value of long-lived assets or asset groups for recoverability whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators of impairment may include a deteriorating business climate, including, but not limited to, declines in energy prices, condition of the asset, or plans to dispose of a long-lived asset significantly before the end of its useful life. We determine if long-lived assets or asset groups are potentially impaired by comparing the undiscounted expected future cash flows to the carrying value when indicators of impairment exist. When the undiscounted cash flow analysis indicates a long-lived asset or asset group may not be recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value. See Note 12 — Asset Impairments for additional information. Equity Method Investments. We regularly monitor and evaluate equity method investments to determine whether they are impaired. An impairment is recorded when the investment has experienced a decline in value that is other-than-temporary in nature. Additionally, if the entity in which we hold an investment recognizes an impairment loss, we would record their proportionate share of that impairment loss and evaluate the investment for an other-than-temporary decline in value. Debt Security Investments. Declines in the fair value of debt security investments below the cost basis are reviewed to determine if such declines are other-than-temporary. If the decline is determined to be other-than-temporary, the amount of the impairment loss is included in earnings. Equity Security Investments. Equity investments with readily determinable fair values are measured and recorded at fair value with any changes in fair value recorded in earnings. Investments in equity securities without readily determinable fair values are qualitatively assessed for impairment each reporting period. If it is determined that the equity security is impaired, an impairment loss will be recognized in earnings to the amount by which the security’s carrying amount exceeds its fair value. Derivative Financial Instruments All derivatives are recognized on the balance sheet at their fair value unless they qualify for certain exceptions, including NPNS. For derivatives intended to serve as economic hedges, changes in fair value are recognized in earnings each period. Amounts classified in earnings are included in Operating revenue, Purchased power and fuel, Interest expense, or Other, net in the Consolidated Statements of Operations and Comprehensive Income based on the activity the transaction is economically hedging. While most of the derivatives serve as economic hedges, there are also derivatives entered into for proprietary trading purposes, subject to our RMP, and changes in the fair value of those derivatives are recorded in revenue or expense in the Consolidated Statements of 92 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 1 — Significant Accounting Policies Operations and Comprehensive Income. Cash inflows and outflows related to derivative instruments are included as a component of operating, investing, or financing cash flows in the Consolidated Statements of Cash Flows, depending on the nature of each transaction. As part of the energy marketing business, we enter contracts to buy and sell energy to meet the requirements of our customers. These contracts include short-term and long-term commitments to purchase and sell energy and energy-related products in the energy markets with the intent and ability to deliver or take delivery of the underlying physical commodity. NPNS are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period and will not be financially settled. Revenues and expenses on derivative contracts that qualify, and are designated, as NPNS are recognized when the underlying physical transaction is completed. While these contracts are considered derivative financial instruments, they are not required to be recorded at fair value. See Note 16 — Derivative Financial Instruments for additional information. Retirement Benefits Exelon sponsored defined benefit pension plans and OPEB plans as described in Note 15 — Retirement Benefits . The plan obligations and costs of providing benefits under these plans were measured as of December 31, 2021. We accounted for our participation in Exelon’s pension and OPEB plans by applying multi-employer accounting. Exelon allocated costs related to its pension and OPEB plans to its subsidiaries based on both active and retired employee participation in each plan. We included the service cost and non-service cost components in Operating and maintenance expense and Property, plant, and equipment, net in the consolidated financial statements. 2. Mergers, Acquisitions, and Dispositions CENG Put Option Prior to August 6, 2021, we owned a 50.01 % membership interest in CENG, a joint venture with EDF, which wholly owns the Calvert Cliffs and Ginna nuclear stations and Nine Mile Point Unit 1, in addition to an 82 % undivided ownership interest in Nine Mile Point Unit 2. CENG is 100% consolidated in our financial statements. See Note 21 — Variable Interest Entities for additional information. On April 1, 2014, we entered into various agreements including a NOSA, an amended LLC Operating Agreement, an Employee Matters Agreement, and a Put Option Agreement, among others with EDF. Under the amended LLC Operating Agreement, CENG made a $ 400 million special distribution to EDF and committed to make preferred distributions to us until we had received aggregate distributions of $ 400 million plus a return of 8.50 % per annum. Under the terms of the Put Option Agreement, EDF had the option to sell its 49.99 % equity interest in CENG exercisable beginning on January 1, 2016 and thereafter until June 30, 2022. On November 20, 2019, we received notice of EDF’s intention to exercise the put option, and the put automatically exercised on January 19, 2020 at the end of the sixty-day advance notice period. The transaction required approval by FERC and the NYPSC, which approvals were received on July 30, 2020 and April 15, 2021, respectively. On August 6, 2021, we entered into a settlement agreement pursuant to which we purchased EDF's equity interest in CENG for a net purchase price of $ 885 million, which includes, among other things, an adjustment for EDF's share of the outstanding balance of the preferred distribution payable to us by CENG. The difference between the net purchase price and EDF's noncontrolling interest as of August 6, 2021 was recorded to Membership interest in the Consolidated Balance Sheet. As a result of the transaction, we also recorded deferred tax liabilities of $ 288 million in Membership interest in the Consolidated Balance Sheet. See Note 14 — Income Taxes for additional information. 93 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 2 — Mergers, Acquisitions, and Dispositions The following table summarizes the effects of the changes in our ownership interest in CENG in Members Equity: For the Year Ended December 31, 2021 Net loss attributable to membership interest $ ( 205 ) Pre-tax increase in membership interest for purchase of EDF's 49.99 % equity interest (a) 1,080 Decrease in membership interest due to deferred tax liabilities resulting from purchase of EDF's 49.99 % equity interest (a) ( 288 ) Change from net loss attributable to membership interest and transfers from noncontrolling interest $ 587 __________ (a) Represents non-cash activity in the consolidated financial statements. Agreement for Sale of Our Solar Business On December 8, 2020, we entered into an agreement with an affiliate of Brookfield Renewable, for the sale of a significant portion of our solar business, including 360 MW of generation in operation or under construction across more than 600 sites across the United States. We will retain certain solar assets not included in this agreement, primarily Antelope Valley. Completion of the transaction contemplated by the sale agreement was subject to the satisfaction of several closing conditions that were satisfied in the first quarter of 2021. The sale was completed on March 31, 2021 for a purchase price of $ 810 million. We received cash proceeds of $ 675 million, net of $ 125 million long-term debt assumed by the buyer and certain working capital and other post-closing adjustments. We recognized a pre-tax gain of $ 68 million which is included in Gain on sales of assets and businesses in the Consolidated Statement of Operations and Comprehensive Income. See Note 17 — Debt and Credit Agreements for additional information on the SolGen nonrecourse debt included as part of the transaction. Agreement for Sale of Our Biomass Facility On April 28, 2021, we entered into a purchase agreement with ReGenerate, under which ReGenerate agreed to purchase our interest in the Albany Green Energy biomass facility. As a result, in the second quarter of 2021, we recorded a pre-tax impairment charge of $ 140 million in Operating and maintenance expense in the Consolidated Statement of Operations and Comprehensive Income. Completion of the transaction was subject to the satisfaction of various customary closing conditions that were satisfied in the second quarter of 2021. The sale was completed on June 30, 2021 for a net purchase price of $ 36 million. Disposition of Oyster Creek On July 31, 2018, we entered into an agreement with Holtec and its indirect wholly owned subsidiary, OCEP, for the sale and decommissioning of Oyster Creek located in Forked River, New Jersey, which permanently ceased generation operations on September 17, 2018. Completion of the transaction contemplated by the sale agreement was subject to the satisfaction of several closing conditions, including approval of the license transfer from the NRC and other regulatory approvals, and a private letter ruling from the IRS, which were satisfied in the second quarter of 2019. The sale was completed on July 1, 2019. We recognized a loss on the sale in the third quarter of 2019, which was immaterial. Under the terms of the transaction, we transferred to OCEP substantially all the assets associated with Oyster Creek, including assets held in NDT funds, along with the assumption of liability for all responsibility for the site, including full decommissioning and ongoing management of the SNF until it is moved offsite. The terms of the transaction also include various forms of performance assurance for the obligations of OCEP to timely complete the required decommissioning, including a parental guaranty from Holtec for all performance and payment obligations of OCEP, and a requirement for Holtec to deliver a letter of credit to us upon the occurrence of specified events. 94 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 3 — Regulatory Matters 3. Regulatory Matters The following matters below discuss the status of our material regulatory and legislative proceedings. Impacts of the February 2021 Extreme Cold Weather Event and Texas-based Generating Assets Outages Beginning on February 15, 2021, our Texas-based generating assets within the ERCOT market, specifically Colorado Bend II, Wolf Hollow II, and Handley, experienced outages as a result of extreme cold weather conditions. In addition, those weather conditions drove increased demand for service, dramatically increased wholesale power prices, and also increased gas prices in certain regions. In response to the high demand and significantly reduced total generation on the system, the PUCT directed ERCOT to use an administrative price cap of $ 9,000 per MWh during firm load shedding events. The estimated impact to our Net income for the year ended December 31, 2021 arising from these market and weather conditions was a reduction of approximately $ 800 million. The ultimate impact to our consolidated financial statements may be affected by a number of factors, including the impacts of customer and counterparty defaults and recoveries, any additional solutions to address the financial challenges caused by the event, and related litigation and contract disputes. During February and March 2021, various parties with differing interests, including generators and retail providers, filed requests with the PUCT to void the PUCT’s orders setting prices at $ 9,000 per MWh during firm load shedding events. Other requests were made for the PUCT to enforce its order and reduce prices for 33 hours between February 18 and February 19 after firm load shedding ceased, and to cap ancillary services at $ 9,000 per MWh. On March 2, 2021, a third-party filed a notice of appeal in the Court of Appeals for the Third District of Texas challenging the validity of the PUCT’s actions. We intervened in that appeal and filed our initial brief on June 2, 2021 and reply brief on November 5, 2021. On April 19, 2021, we filed a declaratory action and request for judicial review of the PUCT’s orders setting prices at $ 9,000 per MWh in the District Court of Travis County, Texas. We subsequently requested that the District Court of Travis County, Texas stay its proceeding pending action by the Court of Appeals in the third-party proceeding. On May 17, 2021, we amended our petition for declaratory action and request for judicial review pending in the District Court of Travis County, Texas. We cannot reasonably predict the outcome of these proceedings or the potential financial statement impact. Due to the event, a number of ERCOT market participants experienced bankruptcies or defaulted on payments to ERCOT, resulting in approximately a $ 3.0 billion payment shortfall in collections, which is allocated to the remaining ERCOT market participants. As of December 31, 2021, we have recorded our estimated portion of this obligation, net of legislative solutions, of approximately $ 17 million on a discounted basis, which is to be paid over a term of 83 years. ERCOT rules historically have limited recovery of default from market participants to $ 2.5 million per month market-wide. In February 2021, the PUCT gave ERCOT discretion to disregard those rules, but ERCOT has declined to exercise that discretion as to the imposition of uplift charges. On March 8, 2021, a third-party filed a notice of appeal in the Court of Appeals for the Third District of Texas challenging the validity of the PUCT's order to ERCOT in February 2021. We intervened in that appeal and filed an initial brief on July 7, 2021. The case has been stayed until March 3, 2022 to afford time for the PUCT to respond to ERCOT's November 18, 2021 request that the PUCT withdraw its February 2021 order. On May 7, 2021, we filed a declaratory action and request for judicial review of the PUCT's order in the District Court of Travis County, Texas. We subsequently requested that the District Court of Travis County, Texas stay its proceeding pending action by the Court of Appeals in the third-party proceeding. We cannot reasonably predict the outcome of these proceedings or the potential financial statement impact. Additionally, several legislative proposals were introduced in the Texas legislature during February and March 2021 concerning the amount, timing and allocation of recovery of the $ 3.0 billion shortfall, as well as recovery of other costs associated with the PUCT's directive to set prices at $ 9,000 per MWh. Two of these proposals were enacted into law in June 2021 and establish financing mechanisms that ERCOT and certain market participants can utilize to fund amounts owed to ERCOT. We participated in proceedings before the PUCT addressing the proposed allocation of the $ 2.1 billion in securitized funds for reliability and ancillary service charges over $ 9,000 per MWh. In September 2021, we entered into a settlement agreement and stipulation to resolve the allocation issues. The PUCT approved the settlement agreement and stipulation on October 13, 2021. In addition, other legislative proposals were introduced in the Texas legislature during February and March 2021 addressing cold-weather preparation for power plants and natural gas production and transportation 95 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 3 — Regulatory Matters infrastructure and the market structure for reliability services. The Texas legislature addressed these proposals by enacting a bill with a broad set of market reforms that, among other things, directed the PUCT to establish weatherization standards for electric generators within six months of enactment and gave the PUCT authority to impose administrative penalties if the new proposed standards, once adopted, are not met. On October 21, 2021, the PUCT adopted a rule change requiring generators by December 1, 2021 to complete a number of specified winter readiness preparations and to submit to ERCOT a report describing and certifying the completion of those preparations. The PUCT described these requirements as the first phase of its actions with respect to winter preparedness, which we completed timely, and will be followed by a second phase consisting of a year-round set of weather preparedness standards to be informed by a weather study conducted by ERCOT and submitted to the PUCT on December 15, 2021. The legislation also directs the PUCT to evaluate whether additional ancillary services are needed for reliability in the ERCOT power region to provide adequate incentives for dispatchable generation. Throughout 2021, we and others submitted various proposals to the PUCT with respect to a range of potential market reforms, including the implementation of additional ancillary service products as well as changes to the high system-wide offer cap and operating reserve demand curve, which remain pending. On December 2, 2021, the PUCT reduced ERCOT’s high system-wide offer cap to $ 5,000 per MWh. In February 2021, more than 70 local distribution companies (LDCs) and natural gas pipelines in multiple states throughout the mid-continent region, where we serve natural gas customers, issued operational flow orders (OFOs), curtailments or other limitations on natural gas transportation or use to manage the operational integrity of the applicable LDC or pipeline system. When in effect, gas transportation or use above these limitations is subject to significant penalties according to the applicable LDCs’ and natural gas pipelines’ tariffs. Gas transportation and supply in many states became restricted due to wells freezing and pipeline compression disruption, while demand was increasing due to the extreme cold temperatures, resulting in extremely high natural gas prices. Due to the extraordinary circumstances, many LDCs and natural gas pipelines have either voluntarily waived or have sought applicable regulatory approvals to waive the tariff penalties associated with the extreme weather event. During March 2021, three natural gas pipelines filed individual petitions with FERC requesting approval to waive OFO penalties. We also filed motions in March 2021 to intervene and filed comments in support of these FERC waiver requests. On March 25, 2021, FERC issued an order on one of the petitions approving a pipeline’s request for a limited waiver of penalties for February 15, 2021. On April 23, 2021, we and several other entities filed a request at FERC for rehearing of this order which was denied on May 24, 2021. We and the other entities filed an appeal of the rehearing of the order with the U.S. Court of Appeals for the D.C. Circuit on July 21, 2021. Additionally, we and the other entities filed a complaint requesting that FERC expand the order to include additional days of the weather event in February, from February 16 through February 19, 2021. On October 21, 2021, FERC denied the complaint finding that a pipeline has the discretion whether to waive penalties under its tariff, and on December 6, 2021 the related D.C. Circuit petition for review was withdrawn. During April 2021, FERC issued orders on the remaining petitions approving the requests to waive the penalties. During May 2021, an LDC filed a motion with the Kansas Corporation Commission (KCC) requesting the KCC to grant a waiver from the tariff and allow the LDC to reduce the amounts assessed by permitting the removal of a multiplier from the penalty calculation. On January 20, 2022, a unanimous settlement was filed with the KCC that amended previously filed October 8, 2021 and November 30, 2021 nonunanimous settlements which, if approved, would resolve this matter. We cannot reasonably predict the outcome of the KCC proceeding. Illinois Regulatory Matters Clean Energy Law. On September 15, 2021, the Illinois Public Act 102-0662 was signed into law by the Governor of Illinois ("Clean Energy Law"). The Clean Energy Law establishes decarbonization requirements for Illinois as well as programs to support the retention and development of emissions-free sources of electricity. Among other things, the Clean Energy Law authorized the IPA to procure up to 54.5 million CMCs from qualifying nuclear plants for a five-year period beginning on June 1, 2022 through May 31, 2027. CMCs are credits for the carbon-free attributes of eligible nuclear power plants in PJM. Our Byron, Dresden, and Braidwood nuclear plants located in Illinois participated in the CMC procurement process and were awarded contracts that commit each plant to operate through May 31, 2027. Pursuant to these contracts, ComEd will procure CMCs based upon the number of MWhs produced annually by each plant, subject to minimum performance requirements. The price to be paid for each CMC was established through a competitive bidding process that included consumer-protection measures that capped the maximum acceptable bid amount and reduces CMC prices by an energy price index, the base residual auction capacity price in the ComEd zone of PJM, and the monetized value of any federal tax 96 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 3 — Regulatory Matters credit or other subsidy, if applicable. The consumer protection measures contained in the new law will result in net payments to ComEd ratepayers if the energy index, the capacity price and applicable federal tax credits or subsidy exceed the CMC contract price. Regulatory or legal challenges regarding the validity or implementation of the Clean Energy Law are possible and we cannot reasonably predict the outcome of any such challenges. See Note 7 – Early Plant Retirements for the impacts of the provisions above on the Illinois nuclear plants and the consolidated financial statements. New Jersey Regulatory Matters New Jersey Clean Energy Legislation. On May 23, 2018, New Jersey enacted legislation that established a ZEC program that provides compensation for nuclear plants that demonstrate to the NJBPU that they meet certain requirements, including that they make a significant contribution to air quality in the state and that their revenues are insufficient to cover their costs and risks. Under the legislation, the NJBPU will issue ZECs to qualifying nuclear power plants and the electric distribution utilities in New Jersey will be required to purchase those ZECs. On April 18, 2019, the NJBPU approved the award of ZECs to Salem 1 and Salem 2. Upon approval, we began recognizing revenue for the sale of New Jersey ZECs in the month they are generated. On March 19, 2021, a three-judge panel of the Superior Court of New Jersey Appellate Division unanimously affirmed the NJBPU’s April 2019 order awarding ZECs for the first eligibility period. On April 8, 2021, New Jersey Rate Counsel filed a notice asking the New Jersey Supreme Court to hear the appeal of the Superior Court’s order. On July 9, 2021, the New Jersey Supreme Court declined to hear the appeal. On October 1, 2020, we and PSEG filed applications seeking ZECs for the second eligibility period (June 2022 through May 2025). On April 27, 2021, the NJBPU approved the award of ZECs to Salem 1 and Salem 2 for the second eligibility period. On May 11, 2021, the New Jersey Rate Counsel appealed the April 27, 2021 decision to the Superior Court of New Jersey Appellate Division. Briefing on the appeal is expected to conclude in the first half of 2022. We cannot reasonably predict the outcome of this proceeding. New England Regulatory Matters Mystic Units 8 and 9 and Everett Marine Terminal Cost of Service Agreement. On March 29, 2018, we notified grid operator ISO-NE of our plans to early retire Mystic Units 8 and 9 absent regulatory reforms on June 1, 2022. On May 16, 2018, we made a filing with FERC to establish cost-of-service compensation and terms and conditions of service for Mystic Units 8 and 9 for the period between June 1, 2022 - May 31, 2024. On December 20, 2018, FERC issued an order accepting the cost of service compensation, reflecting a number of adjustments to the annual fixed revenue requirement and allowing for recovery of a substantial portion of the costs associated with the adjacent Everett Marine Terminal we acquired in October 2018. Those adjustments were reflected in a compliance filing made on March 1, 2019. In the December 20, 2018 order, FERC also directed a paper hearing on ROE using a new methodology. On January 22, 2019, we and several other parties filed requests for rehearing of certain findings in the order. On July 15, 2021, FERC issued an order establishing the ROE to be used in the cost of service agreement for Mystic 8 and 9 at 9.33 %. On August 16, 2021, we and several other parties filed requests for rehearing of certain aspects of the July 15, 2021 order. These requests were denied by operation of law; however, FERC indicated it would address the issues raised in the request in a future order. On July 17, 2020, FERC issued three orders, which together affirmed the recovery of key elements of Mystic's cost of service compensation, including recovery of costs associated with the operation of the Everett Marine Terminal. FERC directed a downward adjustment to the rate base for Mystic Units 8 and 9, the effect of which will be partially offset by elimination of a crediting mechanism for third-party gas sales during the term of the cost of service agreement. In addition, several parties filed protests to a compliance filing by us on September 15, 2020, taking issue with how gross plant in-service was calculated, and we filed an answer to the protests on October 21, 2020. On December 21, 2020, FERC issued an order on rehearing of the three July 17, 2020 orders, clarifying several cost of service provisions. Several parties appealed the December 21, 2020 order to the U.S. Court of Appeals for the D.C. Circuit and that appeal was consolidated with appeals of orders issued December 20, 2018 and July 17, 2020 in the Mystic proceeding. Briefs in support of their petitions for review were filed by us and several other parties on September 7, 2021. Briefing concluded in February 2022 and oral argument is scheduled to begin in May 2022. On February 25, 2021, Mystic made its filing to comply with the December 21, 2020 order. On April 26, 2021, FERC rejected Mystic’s language and directed another compliance filing relating to the claw back provision language, which only applies if Mystic 8 and 9 were to continue operation after the conclusion of the cost-of- 97 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 3 — Regulatory Matters service period. FERC’s April 26, 2021 order also accepted in part and rejected in part Mystic’s September 15, 2020 compliance filing. It directed a further compliance filing in 60 days consistent with the information provided in Mystic’s October 21, 2020 answer to protests, which Mystic filed on June 2, 2021 and FERC accepted on July 29, 2021. On August 16, 2021, Mystic made a compliance filing, reflecting changes to the cost of service agreement to comply with the July 15, 2021 order on ROE. On August 25, 2020, a group of New England generators filed a complaint against us seeking to extend the scope of the claw back provision in the cost-of-service agreement, whereby we would refund certain amounts recovered during the term of the cost of service if it returns to market afterwards. On April 15, 2021 FERC dismissed the complaint. On February 16, 2021, we filed an unopposed motion to voluntarily dismiss an appeal filed with the U.S. Court of Appeals for the D.C. Circuit stemming from a June 2020 complaint filed with FERC against ISO-NE over failures to follow its tariff in evaluating Mystic for transmission security for the 2024 to 2025 Capacity Commitment Period, which was granted on February 18, 2021. See Note 7 — Early Plant Retirements and Note 12 — Asset Impairments for additional information on the impacts of our August 2020 decision to retire Mystic Units 8 and 9 upon expiration of the cost of service agreement. Federal Regulatory Matters PJM and NYISO MOPR Proceedings. PJM and NYISO capacity markets include a MOPR. If a resource is subjected to a MOPR, its offer is adjusted to effectively remove the revenues it receives through a state government-provided financial support program - resulting in a higher offer that may not clear the capacity market. Prior to December 19, 2019, the MOPR in PJM applied only to certain new gas-fired resources. Currently, the MOPR in NYISO applies only to certain resources in downstate New York. For our nuclear facilities in PJM and NYISO that are currently receiving state-supported compensation for carbon-free attributes, an expanded MOPR would require exclusion of such compensation when bidding into future capacity auctions, resulting in an increased risk of these facilities not receiving capacity revenues in future auctions. On December 19, 2019, FERC required PJM to broadly apply the MOPR to all new and existing resources including nuclear, renewables, demand response, energy efficiency, storage, and all resources owned by vertically-integrated utilities. This greatly expanded the breadth and scope of PJM’s MOPR, which became effective as of PJM’s capacity auction for the 2022-23 planning year. While FERC included some limited exemptions, no exemptions were available to state-supported nuclear resources. FERC provided no new mechanism for accommodating state-supported resources other than the existing FRR mechanism (under which an entire utility zone would be removed from PJM’s capacity auction along with sufficient resources to support the load in such zone). In response to FERC’s order, PJM submitted a compliance filing on March 18, 2020 wherein PJM proposed tariff language interpreting and implementing FERC's directives, and proposed a schedule for resuming capacity auctions that is contingent on the timing of FERC's action on the compliance filing. On April 16, 2020, FERC issued an order largely denying most requests for rehearing of FERC's December 2019 order but granting a few clarifications that required an additional PJM compliance filing which PJM submitted on June 1, 2020. A number of parties, including us, have filed petitions for review of FERC's orders in this proceeding, which remain pending before the Court of Appeals for the Seventh Circuit. As a result, the MOPR applied in the capacity auction for the 2022-23 planning year to our owned or jointly owned nuclear plants in those states receiving a benefit under the Illinois ZES, and the New Jersey ZEC program. The MOPR prevented Quad Cities from clearing in that capacity auction. At the direction of the PJM Board of Managers, PJM and its stakeholders developed further MOPR reforms to ensure that the capacity market rules respect and accommodate state resource preferences such as the ZEC programs. PJM filed related tariff revisions at FERC on July 30, 2021 and, on September 29, 2021, PJM's 98 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 3 — Regulatory Matters proposed MOPR reforms became effective by operation of law. Under the new tariff provisions, the MOPR will no longer apply to any of our owned or jointly owned nuclear plants. Requests for rehearing of FERC’s notice establishing the effective date for PJM’s proposed market reforms were filed in October 2021 and denied by operation of law on November 4, 2021. Several parties have filed petitions for review of FERC's orders in this proceeding, which remain pending before the Court of Appeals for the Third Circuit. We are strenuously opposing these appeals. We cannot reasonably predict the outcome of this proceeding. On February 20, 2020, FERC issued an order rejecting requests to expand NYISO’s version of the MOPR (referred to as buyer-side mitigation rules) beyond its current limited applicability to certain resources in downstate. However, on October 14, 2020, two natural gas-fired generators in New York filed a complaint at FERC seeking to expand the MOPR in NYISO to apply to all resources, new and existing, across the entire NYISO market. We are strenuously opposing expansion of FERC’s MOPR policies in the NYISO market. While it is too early in the proceeding to predict its outcome and there are significant differences between the NYISO and PJM markets that would justify a different result, if FERC applies the MOPR in NYISO broadly as requested in the complaint, our facilities in NYISO that are receiving ZEC compensation may be at increased risk of not clearing the capacity auction. If our state-supported nuclear plants in PJM or NYISO are subjected to a MOPR or equivalent without compensation under an FRR or similar program, it could have a material adverse impact on our financial statements, which we cannot reasonably estimate at this time. Operating License Renewals Conowingo Hydroelectric Project. On August 29, 2012, we submitted an application to FERC for a new license for the Conowingo Hydroelectric Project (Conowingo). In connection with our efforts to obtain a water quality certification pursuant to Section 401 of the Clean Water Act (401 Certification) from MDE for Conowingo, we had been working with MDE and other stakeholders to resolve water quality licensing issues, including: (1) water quality, (2) fish habitat, and (3) sediment. On April 21, 2016, we and the U.S. Fish and Wildlife Service of the U.S. Department of the Interior executed a settlement agreement (DOI Settlement) resolving all fish passage issues between the parties. On April 27, 2018, MDE issued its 401 Certification for Conowingo. As issued, the 401 Certification contained numerous conditions, including those relating to reduction of nutrients from upstream sources, removal of all visible trash and debris from upstream sources, and implementation of measures relating to fish passage. On October 29, 2019, we and MDE filed with FERC a Joint Offer of Settlement (Offer of Settlement) that would resolve all outstanding issues relating to the 401 Certification. Pursuant to the Offer of Settlement, the parties submitted Proposed License Articles to FERC to be incorporated by FERC into the new license in accordance with FERC’s discretionary authority under the Federal Power Act. Among the Proposed License Articles were modifications to river flows to improve aquatic habitat, eel passage improvements, and initiatives to support rare, threatened and endangered wildlife. On March 19, 2021, FERC issued a new 50-year license for Conowingo, effective March 1, 2021. FERC adopted the Proposed License Articles into the new license, only making modifications it deemed necessary to allow FERC to enforce the Proposed License Articles. Consistent with the Offer of Settlement, FERC found that MDE waived its 401 Certification and pursuant to a separate agreement with MDE (MDE Settlement), we agreed to implement additional environmental protection, mitigation, and enhancement measures over the 50-year term of the new license. These measures address mussel restoration and other ecological and water quality matters, among other commitments. On April 19, 2021, a few environmental groups filed with FERC a petition for rehearing requesting that FERC reconsider the issuance of the new Conowingo license, which was denied by operation of law on May 20, 2021. On June 17, 2021, the petitioners appealed FERC’s ruling to the U.S. Court of Appeals for the D.C. Circuit. On July 15, 2021, FERC issued an order addressing the arguments raised on rehearing, affirming the determinations of its March 19, 2021 order. We cannot predict the outcome of this proceeding. The financial impact of the DOI and MDE Settlements and other anticipated license commitments are estimated to be $ 10 million to $ 12 million per year, on average, recognized over the new license term, including capital and operating costs. The actual timing and amount of the majority of these costs are not currently fixed and will vary from year to year throughout the life of the new license. 99 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 3 — Regulatory Matters Peach Bottom Units 2 and 3. On March 6, 2020, the NRC approved a second 20-year license renewal for Peach Bottom Units 2 and 3. Peach Bottom Units 2 and 3 are now licensed to operate through 2053 and 2054, respectively. See Note 8 – Property, Plant, and Equipment for additional information regarding the estimated useful life and depreciation provisions for Peach Bottom. On February 24, 2022, the NRC issued an order related to its review of our subsequent license renewal application for Peach Bottom. While the NRC had previously granted subsequent license renewal to the Peach Bottom units, the NRC was responding to a request for hearing that had not previously been adjudicated. In its decision, the NRC reversed itself and concluded that the previous environmental review required by the National Environmental Policy Act (NEPA) was incomplete because it did not adequately address environmental impacts resulting from extending the units’ licenses by 20 years. As a result, the NRC directed its staff to change the expiration dates for the licenses back to 2033 and 2034, until the completion of the NEPA analysis. The NRC directed, however, that the subsequently renewed licenses themselves remain in effect. The NRC also stated that it fully expects that the staff will complete its update of the NEPA analysis before 2033. To date, the NRC staff has not yet taken action to cause amendment of the licenses. We are reviewing the decision and considering our options. We cannot reasonably predict the outcome of this proceeding however any change to the current license expiration dates could have a material adverse financial statement impact. 4. Revenue from Contracts with Customers We recognize revenue from contracts with customers to depict the transfer of goods or services to customers at an amount that we expect to be entitled to in exchange for those goods or services. Our primary sources of revenue include competitive sales of power, natural gas, and other energy-related products and services. The performance obligations, revenue recognition, and payment terms associated with these sources of revenue are further discussed in the table below. There are no significant financing components for these sources of revenue. Unless otherwise noted, for each of the significant revenue categories and related performance obligations described below, we have the right to consideration from the customer in an amount that corresponds directly with the value transferred to the customer for the performance completed to date. Therefore, we generally recognize revenue in the amount for which we have the right to invoice the customer. As a result, there are generally no significant judgments used in determining or allocating the transaction price. 100 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 4 — Revenue from Contracts with Customers Revenue Source Description Performance Obligation Timing of Revenue Recognition Payment Terms Competitive Power Sales Sales of power and other energy-related commodities to wholesale and retail customers across multiple geographic regions through our customer-facing business. Various, including the delivery of power (generally delivered over time) and other energy-related commodities such as capacity (generally delivered over time), ZECs, RECs or other ancillary services (generally delivered at a point in time). Concurrently as power is generated for bundled power sale contracts. (a) Within the month following delivery to the customer. Competitive Natural Gas Sales Sales of natural gas on a full requirement basis or for an agreed upon volume to commercial and residential customers. Delivery of natural gas to the customer. Over time as the natural gas is delivered and consumed by the customer. Within the month following delivery to the customer. Other Competitive Products and Services Sales of other energy-related products and services such as long-term construction and installation of energy efficiency assets and new power generating facilities, primarily to commercial and industrial customers. Construction and/or installation of the asset for the customer. Revenues and associated costs are recognized throughout the contract term using an input method to measure progress towards completion. (b) Within 30 or 45 days from the invoice date. __________ (a) Certain contracts may contain limits on the total amount of revenue we are able to collect over the entire term of the contract. In such cases, we estimate the total consideration expected to be received over the term of the contract net of the constraint and allocate the expected consideration to the performance obligations in the contract such that revenue is recognized ratably over the term of the entire contract as the performance obligations are satisfied. (b) The method recognizes revenue based on the various inputs used to satisfy the performance obligation, such as costs incurred and total labor hours expended. The total amount of revenue that will be recognized is based on the agreed upon contractually-stated amount. The average contract term for these projects is approximately 18 months. We incur incremental costs in order to execute certain retail power and gas sales contracts. These costs, which primarily relate to retail broker fees and sales commissions, are capitalized when incurred as contract acquisition costs and were not material as of December 31, 2021 and 2020. Contract Balances Contract Assets We record contract assets for the revenue recognized on the construction and installation of energy efficiency assets and new power generating facilities before we have an unconditional right to bill for and receive the consideration from the customer. These contract assets are subsequently reclassified to receivables when the right to payment becomes unconditional. We record contract assets and contract receivables in Other current assets and Customer accounts receivable, net, respectively, in the Consolidated Balance Sheets. The following table provides a rollforward of the contract assets reflected in the Consolidated Balance Sheets. 101 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 4 — Revenue from Contracts with Customers Contract Assets Balance as of December 31, 2019 $ 174 Amounts reclassified to receivables ( 86 ) Revenues recognized 68 Contract assets reclassified as held-for-sale ( 12 ) Balance as of December 31, 2020 144 Amounts reclassified to receivables ( 59 ) Revenues recognized 52 Amounts previously held-for-sale 12 Balance as of December 31, 2021 $ 149 Contract Liabilities We record contract liabilities when consideration is received or due prior to the satisfaction of the performance obligations. We record contract liabilities in Other current liabilities and Other noncurrent liabilities in the Consolidated Balance Sheets. These contract liabilities primarily relate to upfront consideration received or due for equipment service plans and the Illinois ZEC program that introduces a cap on the total consideration to be received by us. The following table provides a rollforward of the contract liabilities reflected in the Consolidated Balance Sheets. Contract Liabilities Balance as of December 31, 2018 $ 42 Consideration received or due 287 Revenues recognized ( 258 ) Balance as of December 31, 2019 71 Consideration received or due 282 Revenues recognized ( 266 ) Contract liabilities reclassified as held-for-sale ( 3 ) Balance as of December 31, 2020 84 Consideration received or due 251 Revenues recognized ( 263 ) Amounts previously held-for-sale 3 Balance as of December 31, 2021 $ 75 The following table reflects revenues recognized in the years ended December 31, 2021, 2020 and 2019, which were included in contract liabilities at December 31, 2020, 2019, and 2018, respectively: 2021 2020 2019 Revenues recognized $ 82 $ 64 $ 32 Transaction Price Allocated to Remaining Performance Obligations The following table shows the amounts of future revenues expected to be recorded in each year for performance obligations that are unsatisfied or partially unsatisfied as of December 31, 2021. This disclosure only includes contracts for which the total consideration is fixed and determinable at contract inception. The average contract term varies by customer type and commodity but ranges from one month to several years. This disclosure excludes our power and gas sales contracts as they contain variable volumes and/or variable pricing. 102 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 4 — Revenue from Contracts with Customers 2022 2023 2024 2025 2026 and thereafter Total Remaining performance obligations $ 350 $ 112 $ 45 $ 26 $ 73 $ 606 Revenue Disaggregation We disaggregate the revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. See Note 5 — Segment Information for the presentation of revenue disaggregation. 5. Segment Information Operating segments are determined based on information used by the CODM in deciding how to evaluate performance and allocate resources. We have five reportable segments consisting of the Mid-Atlantic, Midwest, New York, ERCOT, and all other power regions referred to collectively as “Other Power Regions.” The basis for our reportable segments is the integrated management of our electricity business that is located in different geographic regions, and largely representative of the footprints of ISO/RTO and/or NERC regions, which utilize multiple supply sources to provide electricity through various distribution channels (wholesale and retail). Our hedging strategies and risk metrics are also aligned to these same geographic regions. Descriptions of each of our five reportable segments are as follows: • Mid-Atlantic represents operations in the eastern half of PJM, which includes New Jersey, Maryland, Virginia, West Virginia, Delaware, the District of Columbia, and parts of Pennsylvania and North Carolina. • Midwest represents operations in the western half of PJM and the United States footprint of MISO, excluding MISO’s Southern Region. • New York represents operations within NYISO. • ERCOT represents operations within Electric Reliability Council of Texas that covers a majority of the state of Texas. • Other Power Regions: • New England represents operations within ISO-NE. • South represents operations in the FRCC, MISO’s Southern Region, and the remaining portions of the SERC not included within MISO or PJM. • West represents operations in the WECC, which includes CAISO. • Canada represents operations across the entire country of Canada and includes AESO, OIESO, and the Canadian portion of MISO. The CODM evaluates the performance of our electric business activities and allocates resources based on Revenues less Purchased Power and Fuel Expense (RNF). We believe this is a useful measurement of operational performance, although it is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report. Our operating revenues include all sales to third parties and affiliated sales to Exelon's utility subsidiaries. Purchased power costs include all costs associated with the procurement and supply of electricity including capacity, energy, and ancillary services. Fuel expense includes the fuel costs for our owned generation and fuel costs associated with tolling agreements. The results of our other business activities are not regularly reviewed by the CODM and are therefore not classified as operating segments or included in the regional reportable segment amounts. These activities include natural gas, as well as other miscellaneous business activities that are not significant to our overall operating revenues or results of operations. Further, our unrealized mark-to-market gains and losses on economic hedging activities and our amortization of certain intangible assets and liabilities relating to commodity contracts recorded at fair value from mergers and acquisitions are also excluded 103 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 5 — Segment Information from the regional reportable segment amounts. The CODM does not use a measure of total assets in making decisions regarding allocating resources to or assessing the performance of these reportable segments. The following tables disaggregate the revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. The disaggregation of revenues reflects our two primary products of power sales and natural gas sales, with further disaggregation of power sales provided by geographic region. The following tables also show the reconciliation of reportable segment revenues and RNF to our total revenues and RNF for the years ended December 31, 2021, 2020, and 2019. 2021 Revenues from external customers (a) Contracts with customers Other (b) Total Intersegment Revenues Total Revenues Mid-Atlantic $ 4,381 $ 183 $ 4,564 $ 20 $ 4,584 Midwest 4,265 ( 205 ) 4,060 — 4,060 New York 1,633 ( 57 ) 1,576 ( 1 ) 1,575 ERCOT 896 276 1,172 9 1,181 Other Power Regions 3,937 981 4,918 ( 28 ) 4,890 Total Competitive Businesses Electric Revenues $ 15,112 $ 1,178 $ 16,290 $ — $ 16,290 Competitive Businesses Natural Gas Revenues 1,777 1,602 3,379 — 3,379 Competitive Businesses Other Revenues (c) 365 ( 385 ) ( 20 ) — ( 20 ) Total Consolidated Operating Revenues $ 17,254 $ 2,395 $ 19,649 $ — $ 19,649 2020 Revenues from external customers (a) Contracts with customers Other (b) Total Intersegment Revenues Total Revenues Mid-Atlantic $ 4,785 $ ( 168 ) $ 4,617 $ 28 $ 4,645 Midwest 3,717 312 4,029 ( 5 ) 4,024 New York 1,444 ( 12 ) 1,432 ( 1 ) 1,431 ERCOT 735 198 933 25 958 Other Power Regions 3,586 463 4,049 ( 47 ) 4,002 Total Competitive Businesses Electric Revenues $ 14,267 $ 793 $ 15,060 $ — $ 15,060 Competitive Businesses Natural Gas Revenues 1,283 720 2,003 — 2,003 Competitive Businesses Other Revenues (c) 355 185 540 — 540 Total Consolidated Operating Revenues $ 15,905 $ 1,698 $ 17,603 $ — $ 17,603 104 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 5 — Segment Information 2019 Revenues from external customers (a) Contracts with customers Other (b) Total Intersegment Revenues Total Revenues Mid-Atlantic $ 5,053 $ 17 $ 5,070 $ 4 $ 5,074 Midwest 4,095 232 4,327 ( 34 ) 4,293 New York 1,571 25 1,596 — 1,596 ERCOT 768 229 997 16 1,013 Other Power Regions 3,687 608 4,295 ( 49 ) 4,246 Total Competitive Businesses Electric Revenues $ 15,174 $ 1,111 $ 16,285 $ ( 63 ) $ 16,222 Competitive Businesses Natural Gas Revenues 1,446 702 2,148 62 2,210 Competitive Businesses Other Revenues (c) 440 51 491 1 492 Total Consolidated Operating Revenues $ 17,060 $ 1,864 $ 18,924 $ — $ 18,924 __________ (a) Includes all wholesale and retail electric sales to third parties and affiliated sales to Exelon's utility subsidiaries. (b) Includes revenues from derivatives and leases. (c) Represents activities not allocated to a region. See text above for a description of included activities. Includes unrealized mark-to-market losses of $ 633 million, gains of $ 110 million and losses of $ 4 million for the years ended December 31, 2021, 2020, and 2019, respectively, and the elimination of intersegment revenues. 2021 2020 2019 RNF from external customers (a) Intersegment RNF Total RNF RNF from external customers (a) Intersegment RNF Total RNF RNF from external customers (a) Intersegment RNF Total RNF Mid-Atlantic $ 2,247 $ 17 $ 2,264 $ 2,174 $ 30 $ 2,204 $ 2,637 $ 18 $ 2,655 Midwest 2,717 — 2,717 2,902 — 2,902 2,994 ( 32 ) 2,962 New York 1,151 10 1,161 983 14 997 1,081 13 1,094 ERCOT ( 668 ) ( 157 ) ( 825 ) 407 19 426 338 ( 30 ) 308 Other Power Regions 984 ( 93 ) 891 759 ( 94 ) 665 694 ( 74 ) 620 Total RNF for Reportable Segments $ 6,431 $ ( 223 ) $ 6,208 $ 7,225 $ ( 31 ) $ 7,194 $ 7,744 $ ( 105 ) $ 7,639 Other (b) 1,055 223 1,278 793 31 824 324 105 429 Total RNF $ 7,486 $ — $ 7,486 $ 8,018 $ — $ 8,018 $ 8,068 $ — $ 8,068 __________ (a) Includes purchases and sales from/to third parties and affiliated sales to Exelon's utility subsidiaries. (b) Other represents activities not allocated to a region. See text above for a description of included activities. Primarily includes: • unrealized mark-to-market gains of $ 565 million and $ 295 million and losses of $ 215 million for the years ended December 31, 2021, 2020, and 2019, respectively; • accelerated nuclear fuel amortization associated with the announced early plant retirements as discussed in Note 7 - Early Plant Retirements of $ 148 million, $ 60 million, and $ 13 million for the years ended December 31, 2021, 2020, and 2019, respectively; and • the elimination of intersegment RNF. 105 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 6 — Accounts Receivable 6. Accounts Receivable Allowance for Credit Losses on Accounts Receivable The following table presents the rollforward of Allowance for Credit Losses on Customer Accounts Receivable. Allowance for Credit Losses Balance as of December 31, 2019 $ 80 Plus: Current period provision for expected credit losses 13 Less: Write-offs, net of recoveries (a) 5 Less: Sale of customer accounts receivable (b) 56 Balance as of December 31, 2020 (c) 32 Plus: Current period provision for expected credit losses 30 Less: Write-offs, net of recoveries (a) 7 Balance as of December 31, 2021 (c) $ 55 __________ (a) Recoveries were not material. (b) See below for additional information on the sale of customer accounts receivable in the second quarter of 2020. (c) Allowance for Credit Losses on Other Accounts Receivable was not material as of December 31, 2021 and 2020, respectively. Unbilled Customer Revenue We recorded $ 373 million and $ 258 million of unbilled customer revenues in Customer accounts receivables, net in the Consolidated Balance Sheets as of December 31, 2021 and 2020, respectively. Sales of Customer Accounts Receivable On April 8, 2020, NER, a bankruptcy remote, special purpose entity, which is wholly owned by us, entered into a revolving accounts receivable financing arrangement with a number of financial institutions and a commercial paper conduit (the Purchasers) to sell certain customer accounts receivable (the Facility). The Facility had a maximum funding limit of $ 750 million and was scheduled to expire on April 7, 2021, unless renewed by the mutual consent of the parties in accordance with its terms. The Facility was renewed on March 29, 2021. The Facility term was extended through March 29, 2024, unless further renewed by the mutual consent of the parties, and the maximum funding limit was increased to $ 900 million. Under the Facility, NER may sell eligible short-term customer accounts receivable to the Purchasers in exchange for cash and subordinated interest. The transfers are reported as sales of receivables in the consolidated financial statements. The subordinated interest in collections upon the receivables sold to the Purchasers is referred to as the DPP, which is reflected in Other current assets in the Consolidated Balance Sheets. The Facility requires the balance of eligible receivables to be maintained at or above the balance of cash proceeds received from the Purchasers. To the extent the eligible receivables decrease below such balance, we are required to repay cash to the Purchasers. When eligible receivables exceed cash proceeds, we have the ability to increase the cash received up to the maximum funding limit. These cash inflows and outflows impact the DPP. On April 8, 2020, we derecognized and transferred approximately $ 1.2 billion of receivables at fair value to the Purchasers in exchange for approximately $ 500 million in cash purchase price and $ 650 million of DPP. During the first quarter of 2021, we received additional cash of $ 250 million from the Purchasers for the remaining available funding in the Facility. Additionally, during the first quarter of 2021, we received cash of approximately $ 150 million from the Purchasers in connection with the increased funding limit at the time of the Facility renewal. During the second quarter of 2021, we returned cash of $ 50 million to the Purchasers due to the eligible receivables decreasing temporarily. Subsequently, in the second quarter, we received cash of $ 50 million from the Purchasers as a result of an increase in the eligible receivable balance. The $ 50 million cash outflow and 106 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 6 — Accounts Receivable inflow is included in the Collection of DPP line in Cash flows from investing activities in the Consolidated Statement of Cash Flows. The following table summarizes the impact of the sale of certain receivables: As of December 31, 2021 2020 Derecognized receivables transferred at fair value $ 1,265 $ 1,139 Cash proceeds received 900 500 DPP 365 639 For the Years Ended December 31, 2021 2020 Loss on sale of receivables (a) $ 36 $ 30 _________ (a) Reflected in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. For the Years Ended December 31, 2021 2020 Proceeds from new transfers (a) $ 6,095 $ 2,816 Cash collections received on DPP and reinvested in the Facility (b) 3,502 3,771 Cash collections reinvested in the Facility 9,597 6,587 _________ (a) Customer accounts receivable sold into the Facility were $ 9,747 million and $ 6,608 million for the years ended December 31, 2021 and 2020, respectively. (b) Does not include the $ 400 million in cash proceeds received from the Purchasers in the first quarter of 2021. Our risk of loss following the transfer of accounts receivable is limited to the DPP outstanding. Payment of DPP is not subject to significant risks other than delinquencies and credit losses on accounts receivable transferred, which have historically been and are expected to be immaterial. We continue to service the receivables sold in exchange for a servicing fee. We did not record a servicing asset or liability as the servicing fees were immaterial. We recognize the cash proceeds received upon sale in Net cash provided by operating activities in the Consolidated Statements of Cash Flows. The collection and reinvestment of DPP is recognized in Net cash provided by investing activities in the Consolidated Statements of Cash Flows. See Note 18 — Fair Value of Financial Assets and Liabilities and Note 21 — Variable Interest Entities for additional information. Other Purchases and Sales of Customer and Other Accounts Receivables We are required, under supplier tariffs in ISO-NE, MISO, NYISO, and PJM, to sell customer and other receivables to utility companies, which include Exelon's utility subsidiaries. The following table presents the total receivables sold. For the Years Ended December 31, 2021 2020 Total receivables sold $ 147 $ 824 Related party transactions: Receivables sold to Exelon's utility subsidiaries 23 252 107 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 7 — Early Plant Retirements 7. Early Plant Retirements We continuously evaluate factors that affect the current and expected economic value of our plants, including, but not limited to: market power prices, results of capacity auctions, potential legislative and regulatory solutions to ensure plants are fairly compensated for benefits they provide through their carbon-free emissions, reliability or fuel security, and the impact of potential rules from the EPA requiring reduction of carbon and other emissions and the efforts of states to implement those final rules. The precise timing of an early retirement date for any plant, and the resulting financial statement impacts, may be affected by many factors, including the status of potential regulatory or legislative solutions, results of any transmission system reliability study assessments, the nature of any co-owner requirements and stipulations, and NDT fund requirements for nuclear plants, among other factors. However, the earliest retirement date for any plant would usually be the first year in which the unit does not have capacity or other obligations, and where applicable, just prior to its next scheduled nuclear refueling outage. Nuclear Generation On August 27, 2020, we announced our intention to permanently cease our operations at Byron in September 2021 and at Dresden in November 2021. Neither of these nuclear plants cleared in PJM’s capacity auction for the 2022-2023 planning year held in May 2021. Our Braidwood and LaSalle nuclear plants in Illinois did clear in the capacity auction, but were also showing increased signs of economic distress. On September 15, 2021, the Illinois Public Act 102-0662 was signed into law by the Governor of Illinois ("Clean Energy Law"). The Clean Energy Law is designed to achieve 100% carbon-free power by 2045 to enable the state’s transition to a clean energy economy. Among other things, the Clean Energy Law authorized the IPA to procure up to 54.5 million CMCs from qualifying nuclear plants for a five-year period beginning on June 1, 2022 through May 31, 2027. CMCs are credits for the carbon-free attributes of eligible nuclear power plants in PJM. Our Byron, Dresden, and Braidwood nuclear plants located in Illinois participated in the CMC procurement process and were awarded contracts that commit each plant to operate through May 31, 2027. See Note 3 — Regulatory Matters for additional information. Following enactment of the legislation, we announced on September 15, 2021, that we have reversed our previous decision to retire Byron and Dresden given the opportunity for additional revenue under the Clean Energy Law. In addition, we no longer consider the Braidwood or LaSalle nuclear plants to be at risk for premature retirement. As a result of the decision to early retire Byron and Dresden, we recognized certain one-time charges in the third and fourth quarters of 2020 related to materials and supplies inventory reserve adjustments, employee-related costs including severance benefit costs, and construction work-in-progress impairments, among other items. In addition, there were ongoing annual financial impacts stemming from shortening the expected economic useful lives of these nuclear plants primarily related to accelerated depreciation of plant assets (including any ARC), accelerated amortization of nuclear fuel, and changes in ARO accretion expense associated with the changes in decommissioning timing and cost assumptions to reflect an earlier retirement date. In the third quarter of 2021, we reversed $ 81 million of severance benefit costs and $ 13 million of other one-time charges initially recorded in Operating and maintenance expense in the third and fourth quarters of 2020 associated with the early retirements. In addition, we updated the expected economic useful life for both facilities to 2044 and 2046 for Byron Units 1 and 2, respectively, and to 2029 and 2031 for Dresden Units 2 and 3, respectively, the end of the respective NRC operating license for each unit. Depreciation was therefore adjusted beginning September 15, 2021, to reflect these extended useful life estimates. See Note 10 — Asset Retirement Obligations for additional detail on changes to the nuclear decommissioning ARO balances resulting from the initial decision and subsequent reversal of the decision to early retire Byron and Dresden. In Pennsylvania, the TMI nuclear plant did not clear in the May 2017 PJM capacity auction for the 2020-2021 planning year, the third consecutive year that TMI failed to clear the PJM base residual capacity auction and on May 30, 2017, based on these capacity auction results, prolonged periods of low wholesale power prices, and the absence of federal or state policies, we announced that we would permanently cease generation operations at TMI. On September 20, 2019, TMI permanently ceased generation operations. The total impact for the years ended December 31, 2021, 2020, and 2019 in the Consolidated Statements of Operations and Comprehensive Income resulting from the initial decision and subsequent reversal of the decision to early retire Byron and Dresden, and decision to early retire TMI is summarized in the table below. 108 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 7 — Early Plant Retirements Income statement expense (pre-tax) 2021 (a) 2020 (a) 2019 (b) Depreciation and amortization Accelerated depreciation (c) $ 1,805 $ 895 $ 216 Accelerated nuclear fuel amortization 148 60 13 Operating and maintenance One-time charges ( 94 ) 255 — Other charges (d) 9 34 ( 53 ) Contractual offset (e) ( 451 ) ( 364 ) — Total $ 1,417 $ 880 $ 176 _________ (a) Reflects expense for Byron and Dresden. (b) Reflects expense for TMI. (c) Includes the accelerated depreciation of plant assets including any ARC. (d) For 2020 and 2019, reflects the net impacts associated with the remeasurement of the ARO. See Note 10 - Asset Retirement Obligations for additional information. (e) Reflects contractual offset for ARO accretion, ARC depreciation, ARO remeasurement, and excludes any changes in earnings in the NDT funds. Decommissioning-related impacts were not offset for the Byron units starting in the second quarter of 2021 due to the inability to recognize a regulatory asset at ComEd. With our September 15, 2021 reversal of the previous decision to retire Byron, we resumed contractual offset for Byron as of that date. Based on the regulatory agreement with the ICC, decommissioning-related activities are offset in the Consolidated Statements of Operations and Comprehensive Income as long as the net cumulative decommissioning-related activity result in a regulatory liability at ComEd. The offset resulted in an equal adjustment to the noncurrent payables to ComEd. See Note 10 - Asset Retirement Obligations for additional information. We remain committed to continued operations for our other nuclear plants receiving state-supported payments under the Illinois ZES (Clinton and Quad Cities), New Jersey ZEC program (Salem), and the New York CES (FitzPatrick, Ginna, and Nine Mile Point) assuming the continued effectiveness of each program. To the extent each program does not operate as expected over the full term, each of these plants would be at heightened risk for early retirement, which could have a material impact in future financial statements. See Note 3 — Regulatory Matters for additional information on the New Jersey ZEC program. We continue to work with stakeholders on state policy solutions to support continued operation of our nuclear fleet, while also advocating for broader market reforms at the regional and federal level. The absence of such solutions or reforms could have a material unfavorable impact on our future results of operations. Other Generation In March 2018, we notified ISO-NE of our plans to early retire, among other assets, the Mystic Generating Station's units 8 and 9 (Mystic 8 and 9) absent regulatory reforms to properly value reliability and regional fuel security. Thereafter, ISO-NE identified Mystic 8 and 9 as being needed to ensure fuel security for the region and entered into a cost of service agreement with these two units for the period between June 1, 2022 - May 31, 2024. The agreement was approved by FERC in December 2018. On June 10, 2020, we filed a complaint with FERC against ISO-NE stating that ISO-NE failed to follow its tariff with respect to its evaluation of Mystic 8 and 9 for transmission security for the 2024 to 2025 Capacity Commitment Period and that the modifications that ISO-NE made to its unfiled planning procedures to avoid retaining Mystic 8 and 9 should have been filed with FERC for approval. On August 17, 2020, FERC issued an order denying the complaint. As a result, on August 20, 2020, we announced we will permanently cease generation operations at Mystic 8 and 9 at the expiration of the cost of service commitment in May 2024. See Note 3 — Regulatory Matters for additional discussion of Mystic’s cost of service agreement. As a result of the decision to early retire Mystic 8 and 9, we recognized $ 22 million of one-time charges for the year ended December 31, 2020, related to materials and supplies inventory reserve adjustments, among other items. In addition, there are annual financial impacts stemming from shortening the expected economic useful life of Mystic 8 and 9 primarily related to accelerated depreciation of plant assets. We recorded incremental Depreciation and amortization expense of $ 41 million and $ 26 million for the years ended December 31, 2021 and 2020, respectively. See Note 12 — Asset Impairments for impairment assessment considerations of the New England Asset Group. 109 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 8 — Property, Plant, and Equipment 8. Property, Plant, and Equipment The following table presents a summary of property, plant, and equipment by asset category as of December 31, 2021 and 2020: Asset Category December 31, 2021 December 31, 2020 Electric $ 29,910 $ 29,724 Nuclear fuel (a) 5,166 5,399 Construction work in progress 399 450 Other property, plant, and equipment 10 11 Total property, plant, and equipment 35,485 35,584 Less: accumulated depreciation (b) 15,873 13,370 Property, plant, and equipment, net $ 19,612 $ 22,214 __________ (a) Includes nuclear fuel that is in the fabrication and installation phase of $ 859 million and $ 939 million as of December 31, 2021 and 2020, respectively. (b) Includes accumulated amortization of nuclear fuel in the reactor core of $ 2,765 million and $ 2,774 million as of December 31, 2021 and 2020, respectively. The following table presents the average service life for each asset category in number of years: Asset Category Average Service Life (years) Electric 1-52 Nuclear fuel 1-8 Other property, plant, and equipment 1-10 Depreciation provisions are based on the estimated useful lives of the stations, which correspond with the term of the NRC operating licenses for each of our nuclear units. Beginning August 2020, Byron, Dresden, and Mystic depreciation provisions were based on their announced shutdown dates of September 2021, November 2021, and May 2024, respectively. On September 15, 2021, we updated the expected useful lives for Byron and Dresden to reflect the end of the available NRC operating license for each unit. See Note 3 — Regulatory Matters for additional information regarding license renewal and Note 7 — Early Plant Retirements for additional information on the impacts related to Byron, Dresden, and Mystic. Annual depreciation rates for electric generation were 8.67 %, 6.11 %, and 4.35 % for the years ended December 31, 2021, 2020, and 2019, respectively. Nuclear fuel amortization is charged to fuel expense using the unit-of-production method and not included in the annual depreciation rates. Capitalized Interest Capitalized interest was $ 15 million, $ 22 million, and $ 24 million for the years ended December 31, 2021, 2020, and 2019, respectively. See Note 1 — Significant Accounting Policies for additional information regarding property, plant, and equipment policies. 110 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 9 — Jointly Owned Electric Utility Plant 9. Jointly Owned Electric Utility Plant Our material undivided ownership interests in jointly owned nuclear plants as of December 31, 2021 and 2020 were as follows: Nuclear Generation Quad Cities Peach Bottom Salem Nine Mile Point Unit 2 Operator Constellation Constellation PSEG Nuclear Constellation Ownership interest 75.00 % 50.00 % 42.59 % 82.00 % Our share as of December 31, 2021 Plant in service $ 1,211 $ 1,515 $ 756 $ 1,002 Accumulated depreciation 715 628 299 222 Construction work in progress 11 12 20 41 Our share as of December 31, 2020 Plant in service $ 1,188 $ 1,506 $ 717 $ 990 Accumulated depreciation 670 601 265 187 Construction work in progress 13 13 39 25 Our undivided ownership interests are financed with our funds and all operations are accounted for as if such participating interests were wholly owned facilities. Our share of direct expenses of the jointly owned plants are included in Purchased power and fuel and Operating and maintenance expenses in the Consolidated Statements of Operations and Comprehensive Income. 10. Asset Retirement Obligations Nuclear Decommissioning Asset Retirement Obligations We have a legal obligation to decommission our nuclear power plants following the permanent cessation of operations. To estimate our decommissioning obligations related to our nuclear generating stations for financial accounting and reporting purposes, we use a probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models, and discount rates. We update our AROs annually, unless circumstances warrant more frequent updates, based on our review of updated cost studies and our annual evaluation of cost escalation factors and probabilities assigned to various scenarios. We began decommissioning the TMI nuclear plant upon permanently ceasing operations in 2019. See below section for decommissioning of Zion Station. The financial statement impact for changes in the ARO, on an individual unit basis, due to the changes in and timing of estimated cash flows generally result in a corresponding change in the unit’s ARC in Property, plant, and equipment in the Consolidated Balance Sheets. If the ARO decreases for a Non-Regulatory Agreement unit 111 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 10 — Asset Retirement Obligations without any remaining ARC, the corresponding change is recorded as a decrease in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. The following table provides a rollforward of the nuclear decommissioning AROs reflected in the Consolidated Balance Sheets from December 31, 2019 to December 31, 2021: Nuclear Decommissioning AROs Balance as of December 31, 2019 $ 10,504 Net increase due to changes in, and timing of, estimated future cash flows 1,022 Accretion expense 489 Costs incurred related to decommissioning plants ( 93 ) Balance as of December 31, 2020 (a) 11,922 Net increase due to changes in, and timing of, estimated future cash flows 324 Accretion expense 503 Costs incurred related to decommissioning plants ( 73 ) Balance as of December 31, 2021 (a) $ 12,676 __________ (a) Includes $ 72 million and $ 80 million as the current portion of the ARO as of December 31, 2021 and 2020, respectively, which is included in Other current liabilities in the Consolidated Balance Sheets. The net $ 324 million increase in the ARO during 2021 for changes in the amounts and timing of estimated decommissioning cash flows was driven by multiple adjustments throughout the year. These adjustments primarily include: • An increase of approximately $ 550 million for updated cost escalation rates, primarily for labor and energy, and a decrease in discount rates. • An increase of approximately $ 90 million due to revisions to assumed retirement dates for several nuclear plants. • A net decrease of approximately $ 170 million was driven by updates to Byron and Dresden reflecting changes in assumed retirement dates and assumed methods of decommissioning as a result of the reversal of the decision to early retire the plants. See Note 7 — Early Plant Retirements for additional information. • A net decrease of approximately $ 150 million due to lower estimated decommissioning costs resulting from the completion of updated cost studies for seven nuclear plants. The 2021 ARO updates resulted in a decrease of $ 51 million in Operating and maintenance expense for the year ended December 31, 2021 in the Consolidated Statement of Operations and Comprehensive Income. The net $ 1,022 million increase in the ARO during 2020 for changes in the amounts and timing of estimated decommissioning cash flows was driven by multiple adjustments throughout the year. These adjustments primarily include: • A net increase of approximately $ 800 million was driven by updates to Byron and Dresden reflecting changes in assumed retirement dates and assumed methods of decommissioning as a result of the announcement to early retire these plants in 2021. Refer to Note 7 — Early Plant Retirements for additional information. • An increase of approximately $ 360 million resulting from the change in the assumed DOE spent fuel acceptance date for disposal from 2030 to 2035. • A decrease of approximately $ 220 million due to lower estimated decommissioning costs resulting from the completion of updated cost studies primarily for two nuclear plants. The 2020 ARO updates resulted in an increase of $ 60 million in Operating and maintenance expense for the year ended December 31, 2020 in the Consolidated Statement of Operations and Comprehensive Income. 112 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 10 — Asset Retirement Obligations NDT Funds NDT funds have been established for each of our nuclear units to satisfy our nuclear decommissioning obligations, as required by the NRC, and withdrawals from these funds for reasons other than to pay for decommissioning are restricted pursuant to NRC requirements until all decommissioning activities have been completed. Generally, NDT funds established for a particular unit may not be used to fund the decommissioning obligations of any other unit. The NDT funds associated with our nuclear units have been funded with amounts collected from the previous owners and their respective utility customers. PECO is authorized to collect funds, in revenues, through regulated rates for decommissioning the former PECO nuclear plants, and these collections are scheduled through the operating lives of these former PECO plants. The amounts collected from PECO customers are remitted to us and deposited into the NDT funds for the unit for which funds are collected. Every five years, PECO files a rate adjustment with the PAPUC that reflects PECO’s calculations of the estimated amount needed to decommission each of the former PECO units based on updated fund balances and estimated decommissioning costs. The rate adjustment is used to determine the amount collectible from PECO customers. On March 31, 2017, PECO filed its Nuclear Decommissioning Cost Adjustment with the PAPUC proposing an annual recovery from customers of approximately $ 4 million. On August 8, 2017, the PAPUC approved the filing and the new rates became effective January 1, 2018. Any shortfall of funds necessary for decommissioning, determined for each generating station unit, are generally required to be funded by us, with the exception of a shortfall for the current decommissioning activities at Zion Station, where certain decommissioning activities have been transferred to a third-party (see Zion Station Decommissioning below) and the former PECO nuclear plants where, through PECO, we have recourse to collect additional amounts from PECO customers related to a shortfall of NDT funds for those units, subject to certain limitations and thresholds, as prescribed by an order from the PAPUC that limits collection of amounts associated with the first $ 50 million of any shortfall of trust funds compared to decommissioning costs, as well as 5 % of any additional shortfalls, on an aggregate basis for all former PECO units. The initial $ 50 million and up to 5 % of any additional shortfalls would be borne by us. No recourse exists to collect additional amounts from utility customers for any of our other nuclear units. With respect to the former ComEd and former PECO units, any funds remaining in the NDTs after all decommissioning has been completed are required to be refunded to ComEd’s or PECO’s customers, subject to certain limitations that allow sharing of excess funds with us related to the former PECO units. With respect to our other nuclear units, we retain any funds remaining after decommissioning. However, in connection with CENG's acquisition of the Nine Mile Point and Ginna plants and settlements with certain regulatory agencies, certain conditions pertaining to NDT funds apply that, if met, could possibly result in obligations to make payments to certain third parties (clawbacks). For Nine Mile Point and Ginna, the clawback provisions are triggered only in the event that the required decommissioning activities are discontinued or not started or completed in a timely manner. In the event that the clawback provisions are triggered for Nine Mile Point, then, depending upon the triggering event, an amount equal to 50 % of the total amount withdrawn from the funds for non-decommissioning activities as defined in the agreement or 50 % of any excess funds in the trust funds above the amounts required for decommissioning (including SNF management and site restoration) is to be paid to the Nine Mile Point sellers. In the event that the clawback provisions are triggered for Ginna, then an amount equal to any estimated cost savings realized by not completing any of the required decommissioning activities is to be paid to the Ginna sellers. We expect to comply with applicable regulations and timely commence and complete all required decommissioning activities. We had NDT funds totaling $ 16,064 million and $ 14,599 million as of December 31, 2021 and 2020, respectively. The NDT funds also include $ 126 million and $ 134 million for the current portion of the NDT funds as of December 31, 2021 and 2020, respectively, which are included in Other current assets in the Consolidated Balance Sheets. See Note 22 — Supplemental Financial Information for additional information on activities of the NDT funds. Accounting Implications of the Regulatory Agreements with ComEd and PECO Based on the regulatory agreements with the ICC and PAPUC that dictate our obligations related to the shortfall or excess of NDT funds necessary for decommissioning the former ComEd units on a unit-by-unit basis and the former PECO units in total, decommissioning-related activities net of applicable taxes, including realized and 113 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 10 — Asset Retirement Obligations unrealized gains and losses on the NDT funds, depreciation of the ARC, and accretion of the decommissioning obligation are generally offset in the Consolidated Statements of Operations and Comprehensive Income and are recorded as related party balances in the Consolidated Balance Sheets. For the purposes of making this determination, the decommissioning obligation referred to is different, as described below, from the calculation used in the NRC minimum funding obligation filings based on NRC guidelines. For the former PECO units, given the symmetric settlement provisions that allow for continued recovery of decommissioning costs from PECO customers in the event of a shortfall and the obligation for us to ultimately return excess funds to PECO customers (on an aggregate basis for all seven units), decommissioning-related activities are generally offset in the Consolidated Statements of Operations and Comprehensive Income regardless of whether the NDT funds are expected to exceed or fall short of the total estimated decommissioning obligation. The offset of decommissioning-related activities in the Consolidated Statement of Operations and Comprehensive Income results in an equal adjustment to noncurrent payables to or noncurrent receivables from affiliates. Any changes to the existing PECO regulatory agreements could impact our ability to offset decommissioning-related activities in the Consolidated Statement of Operations and Comprehensive Income, and the potential impact to our financial statements could be material. For the former ComEd units, given no further recovery from ComEd customers is permitted and we retain an obligation to ultimately return any unused NDTs to ComEd customers (on a unit-by-unit basis), to the extent the related NDT investment balances are expected to exceed the total estimated decommissioning obligation for each unit, decommissioning-related activities are offset in the Consolidated Statements of Operations and Comprehensive Income which results in us recognizing a noncurrent payable to affiliates. However, given the asymmetric settlement provision that does not allow for continued recovery from ComEd customers in the event of a shortfall, recognition of a regulatory asset at ComEd is not permissible and accounting for decommissioning-related activities for that unit would not be offset, and the impact to the Consolidated Statements of Operations and Comprehensive Income could be material during such periods. During the second and third quarter of 2021, a pre-tax charge of $ 53 million and $ 140 million, respectively, was recorded in the Consolidated Statement of Operations and Comprehensive Income for decommissioning-related activities that were not offset for the Byron units due to contractual offset being temporarily suspended. With our September 15, 2021 reversal of the previous decision to retire Byron and the corresponding adjustment to the ARO for Byron discussed previously, we resumed contractual offset for Byron as of that date. As of December 31, 2021, decommissioning-related activities for all of the former ComEd units, except for Zion (see Zion Station Decommissioning below), are currently offset in the Consolidated Statements of Operations and Comprehensive Income. The decommissioning-related activities related to the Non-Regulatory Agreement Units are reflected in the Consolidated Statements of Operations and Comprehensive Income. Zion Station Decommissioning In 2010, we completed an ASA under which ZionSolutions assumed responsibility for decommissioning Zion Station and we transferred to ZionSolutions substantially all the Zion Station’s assets, including the related NDT funds. Following ZionSolutions' completion of its contractual obligations and transfer of the NRC license back to us, we will store the SNF at Zion Station until it is transferred to the DOE for ultimate disposal, and complete all remaining decommissioning activities associated with the SNF dry storage facility. We had retained our obligation for the SNF upon transfer of the NRC license to us as well as certain NDT assets to fund the obligation to maintain the SNF at Zion Station until transfer to the DOE and to complete all remaining decommissioning activities for the SNF storage facility. Any shortage of funds necessary to maintain the SNF and decommission the SNF storage facility is ultimately required to be funded by us. As of December 31, 2021, the ARO associated with Zion's SNF storage facility is $ 140 million and the NDT funds available to fund this obligation are $ 65 million. NRC Minimum Funding Requirements NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts to decommission the facility at the end of its life. The estimated decommissioning obligations are calculated using an NRC methodology that is different from the ARO recorded in the Consolidated Balance Sheets primarily due to differences in the type of costs included in the 114 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 10 — Asset Retirement Obligations estimates, the basis for estimating such costs, and assumptions regarding the decommissioning alternatives to be used, potential license renewals, decommissioning cost escalation, and the growth rate in the NDT funds. Under NRC regulations, if the minimum funding requirements for radiological decommissioning calculated under the NRC methodology are greater than the future value of the NDT funds, also calculated under the NRC methodology, then the NRC requires resolution of the shortfalls which could include further funding or other financial guarantees. Key assumptions used in the minimum funding calculation for radiological decommissioning costs using the NRC methodology at December 31, 2021 include: (1) consideration of costs only for the removal of radiological contamination at each unit; (2) the option on a unit-by-unit basis to use generic, non-site specific cost estimates; (3) consideration of only one decommissioning scenario for each unit; (4) the plants cease operation at the end of their current license lives (with no assumed license renewals for those units that have not already received renewals); (5) the assumption of current nominal dollar cost estimates that are neither escalated through the anticipated period of decommissioning, nor discounted using the CARFR; and (6) assumed annual after-tax returns on the NDT funds of 2 % ( 3 % for the former PECO units, as specified by the PAPUC). In contrast, the key criteria and assumptions used by us to determine the ARO and to forecast the target growth in the NDT funds as of December 31, 2021 include: (1) the use of site specific cost estimates that are updated at least once every five years; (2) the inclusion in the ARO estimate of all legally unavoidable costs required to decommission the unit (e.g., radiological decommissioning and full site restoration for certain units, on-site SNF maintenance and storage subsequent to ceasing operations and until DOE acceptance, and disposal of certain LLRW); (3) as applicable, the consideration of multiple scenarios where decommissioning and site restoration activities, as applicable, are completed under possible scenarios ranging from 10 to 70 years after the cessation of plant operations or the end of the current licensed operating life; (4) the consideration of multiple end of life scenarios; (5) the measurement of the obligation at the present value of the future estimated costs and an annual average accretion of the ARO of approximately 4 % through a period of approximately 30 years after the end of the extended lives of the units; and (6) an estimated targeted annual pre-tax return on the NDT funds of 5.5 % to 6.3 % (as compared to a historical 5-year annual average pre-tax return of approximately 10.2 %). We are required to provide to the NRC a biennial report by unit (annually for units that have been retired or are within five years of license expiration), based on values as of December 31, addressing our ability to meet the NRC minimum funding levels. Depending on the value of the trust funds, we may be required to take steps, such as providing financial guarantees through surety bonds, letters of credit, or parent company guarantees or making additional contributions to the trusts, which could be significant, to ensure that the trusts are adequately funded and that NRC minimum funding requirements are met. As a result, our cash flows and financial position may be significantly adversely affected. We filed our biennial decommissioning funding status report with the NRC on February 24, 2021 for all units, including our shutdown units, except for Zion Station which is included in a separate report to the NRC submitted by ZionSolutions, LLC. The status report demonstrated adequate decommissioning funding assurance as of December 31, 2020 for all units except for Byron Units 1 and 2. We filed an updated decommissioning funding status report for Byron Units 1 and 2 and Dresden Units 2 and 3 on September 28, 2021 based on their current license expiration dates consistent with our announcements regarding the continued operations of these units. This report demonstrated adequate decommissioning funding assurance as of December 31, 2020 for Byron Units 1 and 2 and Dresden Units 2 and 3. We will file the next decommissioning funding status report with the NRC by March 31, 2022. This report will also reflect the status of decommissioning funding assurance as of December 31, 2021 for shutdown units. As the future values of trust funds change due to market conditions, the NRC minimum funding status of our units will change. In addition, if changes occur to the regulatory agreement with the PAPUC that currently allows amounts to be collected from PECO customers for decommissioning the former PECO units, the NRC minimum funding status of those plants could change at subsequent NRC filing dates. Impact of Separation from Exelon Satisfying a condition precedent, on December 16, 2021, the NYPSC authorized our separation from Exelon and accepted the terms of a Joint Proposal that became binding upon closing of the separation on February 1, 2022. As part of the Joint Proposal, among other items, we have projected completion of radiological decommissioning 115 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 10 — Asset Retirement Obligations and site restoration activities necessary to achieve a partial site release from the NRC (release of the site for unrestricted use, except for any on-site dry cask storage) within 20 years from the end of licensed life for each of our Ginna and FitzPatrick units and from the end of licensed life for the last of the NMP operating units. While there is flexibility under the Joint Proposal for decommissioning timing, we expect to increase the AROs associated with our New York nuclear plants during the first quarter of 2022 to reflect this scenario. The Joint Proposal also required a contribution of $ 15 million to the NDT for NMP Unit 2 in January 2022 and requires various financial assurance mechanisms through the duration of decommissioning and site restoration, including a minimum NDT balance for each unit, adjusted for specific stages of decommissioning, and a parent guaranty for site restoration costs updated annually as site restoration progresses, which must be replaced with a third-party surety bond or equivalent financial instrument in the event we fall below investment grade. See Note 24 — Separation from Exelon for additional information. Non-Nuclear Asset Retirement Obligations We have AROs for plant closure costs associated with our natural gas, oil, and renewable generating facilities, including asbestos abatement, removal of certain storage tanks, restoring leased land to the condition it was in prior to construction of renewable generating stations, and other decommissioning-related activities. See Note 1 — Significant Accounting Policies for additional information on the accounting policy for AROs. The following table provides a rollforward of the non-nuclear AROs reflected in the Consolidated Balance Sheets from December 31, 2019 to December 31, 2021: Non-nuclear AROs Balance as of December 31, 2019 $ 216 Net increase due to changes in, and timing of, estimated future cash flows 2 Development projects 1 Accretion expense 11 Asset divestitures ( 4 ) Payments ( 4 ) AROs reclassified to liabilities held for sale ( 10 ) Balance as of December 31, 2020 212 Net increase due to changes in, and timing of, estimated future cash flows 5 Accretion expense 11 Asset divestitures ( 19 ) Payments ( 3 ) AROs previously held for sale 10 Balance as of December 31, 2021 $ 216 . 11. Leases Lessee We have operating leases for which we are the lessee. The significant types of leases are contracted generation, real estate, and vehicles and equipment. The following table outlines other terms and conditions of the lease agreements as of December 31, 2021. We did not have material finance leases in 2021, 2020, or in 2019. Years Remaining lease terms 1-34 Options to extend the term 1-30 Options to terminate within 1-2 116 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 11 — Leases The components of operating lease costs were as follows: For the Years Ended December 31, 2021 2020 2019 Operating lease costs $ 161 $ 194 $ 222 Variable lease costs 168 234 282 Short-term lease costs — 2 19 Total lease costs (a) $ 329 $ 430 $ 523 __________ (a) Excludes $ 44 million of sublease income recorded for each of the years ended December 31, 2021, 2020, and 2019 respectively. The following table provides additional information regarding the presentation of operating lease ROU assets and lease liabilities in the Consolidated Balance Sheets: As of December 31, 2021 2020 Operating lease ROU assets (a) Other deferred debits and other assets $ 604 $ 726 Operating lease liabilities (a) Other current liabilities 72 132 Other deferred credits and other liabilities 705 775 Total operating lease liabilities $ 777 $ 907 __________ (a) The operating ROU assets and lease liabilities include $ 293 million and $ 429 million, respectively, related to contracted generation as of December 31, 2021, and $ 387 million and $ 528 million, respectively, as of December 31, 2020. The weighted average remaining lease terms, in years, and the weighted average discount rates for operating leases were as follows: Weighted Average Remaining Lease Terms (in Years) Weighted Average Discount Rates As of December 31, 2021 10.1 5.0 % As of December 31, 2020 10.5 4.9 % As of December 31, 2019 10.6 4.8 % Future minimum lease payments for operating leases as of December 31, 2021 were as follows: Year Future Minimum Lease payments 2022 $ 92 2023 99 2024 97 2025 99 2026 100 Remaining years 531 Total 1,018 Interest 241 Total operating lease liabilities $ 777 117 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 11 — Leases Cash paid for amounts included in the measurement of operating lease liabilities was $ 162 million, $ 204 million, and $ 206 million for the years ended December 31, 2021, 2020, and 2019, respectively. ROU assets obtained in exchange for operating lease obligations were $( 2 ) million, $ 3 million, and $ 14 million for the years ended December 31, 2021, 2020, and 2019, respectively. Lessor We have operating leases for which we are the lessor. The significant types of leases are contracted generation and real estate. The following table outlines other terms and conditions of the lease agreements as of December 31, 2021. Years Remaining lease terms 1-18 Options to extend the term 1-5 The components of lease income were as follows: For the Years Ended December 31, 2021 2020 2019 Operating lease income $ 47 $ 47 $ 47 Variable lease income 261 282 258 Future minimum lease payments to be recovered under operating leases as of December 31, 2021 were as follows: Year Minimum lease payments to be recovered 2022 $ 45 2023 45 2024 45 2025 45 2026 45 Remaining years 137 Total $ 362 12. Asset Impairments We evaluate the carrying value of long-lived assets or asset groups for recoverability whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators of impairment may include a deteriorating business climate, including, but not limited to, declines in energy prices, condition of the asset, or plans to dispose of a long-lived asset significantly before the end of its useful life. We determine if long-lived assets or asset groups are potentially impaired by comparing the undiscounted expected future cash flows to the carrying value when indicators of impairment exist. When the undiscounted cash flow analysis indicates a long-lived asset or asset group may not be recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value. The fair value analysis is primarily based on the income approach using significant unobservable inputs (Level 3) including revenue and generation forecasts, projected capital and maintenance expenditures and discount rates. A variation in the assumptions used could lead to a different conclusion regarding the recoverability of an asset or asset group and, thus, could potentially result in material future impairments of our long-lived assets. New England Asset Group In the third quarter of 2020, in conjunction with the retirement announcement of Mystic Units 8 and 9, we completed a comprehensive review of the estimated undiscounted future cash flows of the New England asset group and concluded that the estimated undiscounted future cash flows and fair value of the New England asset 118 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 12 — Asset Impairments group were less than their carrying values. As a result, a pre-tax impairment charge of $ 500 million was recorded in the third quarter of 2020 in Operating and maintenance expense in the Consolidated Statement of Operations and Comprehensive Income. See Note 7 - Early Plant Retirements for additional information. In the second quarter of 2021, an overall decline in the asset group's portfolio value suggested that the carrying value of the New England asset group may be impaired. We completed a comprehensive review of the estimated undiscounted future cash flows of the New England asset group and concluded that the carrying value was not recoverable and that its fair value was less than its carrying value. As a result, a pre-tax impairment charge of $ 350 million was recorded in the second quarter of 2021 in Operating and maintenance expense in the Consolidated Statement of Operations and Comprehensive Income. Contracted Wind Project In the third quarter of 2021, significant long-term operational issues anticipated for a specific wind turbine technology suggested that the carrying value of a contracted wind asset, located in Maryland and part of the CRP joint venture, may be impaired. We completed a comprehensive review of the estimated undiscounted future cash flows and concluded that the carrying value of this contracted wind project was not recoverable and that its fair value was less than its carrying value. As a result, in the third quarter of 2021, a pre-tax impairment charge of $ 45 million was recorded in Operating and maintenance expense, $ 21 million of which was offset in Net income attributable to noncontrolling interests in the Consolidated Statement of Operations and Comprehensive Income. Equity Method Investments in Certain Distributed Energy Companies In the third quarter of 2019, our equity method investments in certain distributed energy companies were fully impaired due to an other-than-temporary decline in market conditions and underperforming projects. We recorded a pre-tax impairment charge of $ 164 million in Equity in losses of unconsolidated affiliates and an offsetting pre-tax $ 96 million in Net income attributable to noncontrolling interests in the Consolidated Statement of Operations and Comprehensive Income. As a result, we accelerated the amortization of investment tax credits associated with these companies and recorded a benefit of $ 46 million in Income taxes. The impairment charge and the accelerated amortization of investment tax credits resulted in a net $ 15 million decrease to our earnings. See Note 21 — Variable Interest Entities for additional information. 13. Intangible Assets Our intangible assets and liabilities, included in Other current assets, Other deferred debits and other assets, Other current liabilities, Other deferred credits and other liabilities in the Consolidated Balance Sheets, consisted of the following as of December 31, 2021 and 2020. The intangible assets and liabilities shown below are generally amortized on a straight line basis, except for unamortized energy contracts which are amortized in relation to the expected realization of the underlying cash flows: December 31, 2021 December 31, 2020 Gross Accumulated Amortization Net Gross Accumulated Amortization Net Unamortized Energy Contracts $ 1,963 $ ( 1,673 ) $ 290 $ 1,963 $ ( 1,642 ) $ 321 Customer Relationships 330 ( 243 ) 87 326 ( 215 ) 111 Trade Name 222 ( 218 ) 4 222 ( 197 ) 25 Total $ 2,515 $ ( 2,134 ) $ 381 $ 2,511 $ ( 2,054 ) $ 457 The following table summarizes the amortization expense related to intangible assets and liabilities for each of the years ended December 31, 2021, 2020, and 2019: 119 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 13 — Intangible Assets For the Years Ended December 31, Amortization Expense (a) 2021 $ 80 2020 81 2019 74 __________ (a) See Note 22 — Supplemental Financial Information for additional information related to the amortization of unamortized energy contracts. The following table summarizes the estimated future amortization expense related to intangible assets and liabilities as of December 31, 2021: For the Years Ending December 31, Estimated Future Amortization Expense 2022 $ 60 2023 53 2024 50 2025 44 2026 37 Renewable Energy Credits RECs are included in Renewable energy credits in the Consolidated Balance Sheets. Purchased RECs are recorded at cost on the date they are purchased. The cost of RECs purchased on a stand-alone basis is based on the transaction price, while the cost of RECs acquired through PPAs represents the difference between the total contract price and the market price of energy at contract inception. Generally, revenue for RECs that are sold to a counterparty under a contract that specifically identifies a power plant is recognized at a point in time when the power is produced. This includes both bundled and unbundled REC sales. Otherwise, the revenue is recognized upon physical transfer of the REC to the customer. The following table presents current RECs as of December 31, 2021 and 2020: As of December 31, 2021 As of December 31, 2020 Current REC's $ 520 $ 621 14. Income Taxes Components of Income Tax Expense or Benefit Income tax expense (benefit) from continuing operations is comprised of the following components: For the Years Ended December 31, 2021 2020 2019 Included in operations: Federal Current $ 394 $ 130 $ 147 Deferred ( 153 ) 150 346 Investment tax credit amortization ( 15 ) ( 25 ) ( 69 ) State Current 36 40 10 Deferred ( 37 ) ( 46 ) 82 Total $ 225 $ 249 $ 516 120 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 14 — Income Taxes Rate Reconciliation The effective income tax rate from continuing operations varies from the U.S. federal statutory rate principally due to the following: For the Years Ended December 31, 2021 (a) 2020 (a) 2019 (a) U.S. federal statutory rate 21.0 % 21.0 % 21.0 % Increase (decrease) due to: State income taxes, net of federal income tax benefit — 0.5 3.8 Qualified NDT fund income 165.1 23.5 12.3 Amortization of investment tax credit, including deferred taxes on basis differences ( 9.0 ) ( 2.6 ) ( 3.0 ) Production tax credits and other credits ( 28.7 ) ( 5.4 ) ( 4.8 ) Noncontrolling interests ( 3.0 ) 3.2 ( 1.2 ) Tax Settlements — ( 10.3 ) — Other 2.6 ( 0.1 ) ( 1.2 ) Effective income tax rate (b) 148.0 % 29.8 % 26.9 % _________ (a) Positive percentages represent income tax expense. Negative percentages represent income tax benefit. (b) The higher effective tax rate in 2021 is primarily due to the impacts of the February 2021 extreme cold weather event on Income before income taxes. Tax Differences and Carryforwards The tax effects of temporary differences and carryforwards, which give rise to significant portions of the deferred tax assets (liabilities), as of December 31, 2021 and 2020 are presented below: As of December 31, 2021 As of December 31, 2020 Plant basis differences $ ( 2,812 ) $ ( 2,592 ) Accrual based contracts ( 38 ) ( 37 ) Derivatives and other financial instruments ( 172 ) ( 41 ) Deferred pension and postretirement obligation ( 274 ) ( 236 ) Nuclear decommissioning activities ( 912 ) ( 742 ) Deferred debt refinancing costs 15 16 Tax loss carryforward 53 55 Tax credit carryforward, net of valuation allowances 778 838 Investment in partnerships ( 252 ) ( 813 ) Other, net 312 347 Deferred income tax liabilities (net) $ ( 3,302 ) $ ( 3,205 ) Unamortized investment tax credits (a) ( 369 ) ( 445 ) Total deferred income tax liabilities (net) and unamortized investment tax credits $ ( 3,671 ) $ ( 3,650 ) __________ (a) Does not include unamortized investment tax credits reclassified to liabilities held for sale as of December 31, 2020. The following table provides our carryforwards, of which the state related items are presented on a post-apportioned basis, and any corresponding valuation allowances as of December 31, 2021. 121 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 14 — Income Taxes Federal As of December 31, 2021 Federal general business credits carryforwards and other carryforwards (a) $ 806 State State net operating losses and other carryforwards 869 Deferred taxes on state tax attributes (net) 74 Valuation allowance on state tax attributes 22 Year in which net operating loss or credit carryforwards will begin to expire (a) 2035 __________ (a) The federal general business credit carryforward will begin expiring in 2035. Tabular Reconciliation of Unrecognized Tax Benefits The following table presents changes in unrecognized tax benefits. Unrecognized tax benefits Balance as of December 31, 2018 $ 408 Change to positions that only affect timing 12 Increases based on tax positions related to 2019 1 Increases based on tax positions prior to 2019 19 Decreases based on tax positions prior to 2019 ( 3 ) Increase from settlements with taxing authorities 4 Balance as of December 31, 2019 441 Increases based on tax positions related to 2020 1 Increases based on tax positions prior to 2020 23 Decreases based on tax positions prior to 2020 (a) ( 346 ) Decrease from settlements with taxing authorities (a) ( 69 ) Balance as of December 31, 2020 50 Change to positions that only affect timing ( 1 ) Increases based on tax positions related to 2021 1 Increases based on tax positions prior to 2021 1 Decreases based on tax positions prior to 2021 ( 2 ) Balance as of December 31, 2021 $ 49 __________ (a) Our unrecognized federal and state tax benefits decreased in the first quarter of 2020 by approximately $ 411 million due to the settlement of a federal refund claim with IRS Appeals. The recognition of these tax benefits resulted in an increase in net income of $ 73 million in the first quarter of 2020, reflecting a decrease to income tax expense of $ 67 million. Recognition of unrecognized tax benefits The following table presents the unrecognized tax benefits that, if recognized, would decrease the effe ctive tax rate. December 31, 2021 $ 39 December 31, 2020 39 December 31, 2019 429 Reasonably possible the total amount of unrecognized tax benefits could significantly increase or decrease within 12 months after the reporting date No amounts are expected to significantly increase or decrease within 12 months after the reporting date. Total amounts of interest and penalties recognized 122 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 14 — Income Taxes We did not record material interest and penalty expense related to tax positions reflected in the Consolidated Balance Sheets. Interest expense and penalty expense are recorded in Interest expense, net and Other, net, respectively, in Other income and deductions in the Consolidated Statements of Operations and Comprehensive Income. Description of tax years open to assessment by major jurisdiction Major Jurisdiction Open Years (a) Federal consolidated income tax returns 2010-2020 Illinois unitary corporate income tax returns 2012-2020 New Jersey separate corporate income tax returns 2017-2018 New York combined corporate income tax returns 2011-2020 Pennsylvania separate corporate income tax returns 2011-2016 Pennsylvania separate corporate income tax returns 2018-2020 __________ (a) Tax years open to assessment include years when we were consolidated by Exelon. See discussion below under the Tax Matters Agreement for responsibility of taxes of these open years. Other Tax Matters CENG Put Option On August 6, 2021, we entered into a settlement agreement with EDF pursuant to which we purchased EDF’s equity interest in CENG. We recorded deferred tax liabilities of $ 288 million against Membership interest in the Consolidated Balance Sheet. The deferred tax liabilities represent the tax effect on the difference between the net purchase price and EDF’s noncontrolling interest as of August 6, 2021. The deferred tax liabilities will reverse during the remaining operating lives and during decommissioning of the CENG nuclear plants. See Note 2 – Mergers, Acquisitions, and Dispositions for additional information. Allocation of Tax Benefits We are a party to an agreement with Exelon and other subsidiaries of Exelon that provides for the allocation of consolidated tax liabilities and benefits (Tax Sharing Agreement). The Tax Sharing Agreement provides that each party is allocated an amount of tax similar to that which would be owed had the party been separately subject to tax. In addition, any net federal and state benefits attributable to Exelon were reallocated to the parties. That allocation was treated as a contribution from Exelon to the party receiving the benefit. The following table presents the allocation of tax benefits from Exelon to us under the Tax Sharing Agreement. December 31, 2021 $ 64 December 31, 2020 64 December 31, 2019 41 Research and Development Activities In the fourth quarter of 2019, we recognized additional tax benefits related to certain research and development activities that qualify for federal and state tax incentives for the 2010 through 2018 tax years, which resulted in an increase in net income of $ 75 million for the year ended December 31, 2019, reflecting a decrease in Income tax expense of $ 66 million. Tax Matters Agreement In connection with the separation, we entered into a Tax Matters Agreement (“TMA”) with Exelon. The TMA will govern the respective rights, responsibilities, and obligations between us and Exelon after the separation with respect to tax liabilities and benefits, tax attributes, tax returns, tax contests and other tax sharing regarding U.S. federal, state, local and foreign income taxes, other tax matters and related tax returns. 123 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 14 — Income Taxes Responsibility and Indemnification for Taxes . As a former subsidiary of Exelon, we will have joint and several liability with Exelon to the IRS and certain state jurisdictions relating to the taxable periods that we were included in federal and state filings. However, the TMA specifies the portion of this tax liability for which we will bear contractual responsibility, and we and Exelon will each agree to indemnify each other against any amounts for which such indemnified party is not responsible. Specifically, we will generally be liable for taxes due and payable in connection with tax returns that we are required to file. We will also generally be liable for our share of certain taxes required to be paid by Exelon with respect to taxable years or periods (or portions thereof) ending on or prior to the separation to the extent that we would have been responsible for such taxes under the existing Exelon tax sharing agreement. Tax Refunds and Attributes . The TMA will provide for the allocation of certain pre-closing tax attributes between us and Exelon. Tax attributes generally will be allocated in accordance with the principles set forth in the existing Exelon tax sharing agreement, unless otherwise required by law. Under the TMA, we will generally be entitled to refunds for taxes for which we are responsible. In addition, it is expected that after the separation, Exelon will have tax credit carryforwards that may be used to offset Exelon’s future tax liabilities. A significant portion of such carryforwards were generated by our business, and we recognized a receivable upon separation for the tax credit carryforwards expected to be utilized by Exelon after separation in accordance with the terms of the TMA. 15. Retirement Benefits Substantially all our current employees participated in Exelon-sponsored defined benefit pension plans and OPEB plans as of December 31, 2021. Substantially all non-union employees and electing union employees hired on or after January 1, 2001 participate in cash balance pension plans. Effective January 1, 2009, substantially all newly-hired union-represented employees participate in cash balance pension plans. Effective February 1, 2018, for most newly-hired non-represented, non-craft, employees, and for certain newly-hired union employees pursuant to their collective bargaining agreements, these newly-hired employees are not eligible for pension benefits, and will instead be eligible to receive an enhanced non-discretionary employer contribution in an Exelon defined contribution savings plan. Effective January 1, 2018, most newly-hired non-represented, non-craft, employees are not eligible for OPEB benefits and employees represented by Local 614 are not eligible for retiree health care benefits. Effective January 1, 2021, most non-represented, non-craft, employees who are under the age of 40 are not eligible for retiree health care benefits. Effective January 1, 2022, management employees retiring on or after that date are no longer eligible for retiree life insurance benefits. 124 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 15 — Retirement Benefits The tables below show the pension and OPEB plans in which our employees participated as of December 31, 2021: Name of Plan Qualified Pension Plans: Exelon Corporation Retirement Program (a) Exelon Corporation Pension Plan for Bargaining Unit Employees (a) Exelon New England Union Employees Pension Plan (a) Exelon Employee Pension Plan for Clinton, TMI, and Oyster Creek (a) Pension Plan of Constellation Energy Group, Inc. (b) Pension Plan of Constellation Energy Nuclear Group, LLC (c) Nine Mile Point Pension Plan (c) Constellation Mystic Power, LLC Union Employees Pension Plan Including Plan A and Plan B (b) Pepco Holdings LLC Retirement Plan (d) Non-Qualified Pension Plans: Exelon Corporation Supplemental Pension Benefit Plan and 2000 Excess Benefit Plan (a) Exelon Corporation Supplemental Management Retirement Plan (a) Constellation Energy Group, Inc. Senior Executive Supplemental Plan (b) Constellation Energy Group, Inc. Supplemental Pension Plan (b) Constellation Energy Group, Inc. Benefits Restoration Plan (b) Constellation Energy Nuclear Plan, LLC Executive Retirement Plan (c) Constellation Energy Nuclear Plan, LLC Benefits Restoration Plan (c) Baltimore Gas & Electric Company Executive Benefit Plan (b) Baltimore Gas & Electric Company Manager Benefit Plan (b) Pepco Holdings LLC 2011 Supplemental Executive Retirement Plan (d) Conectiv Supplemental Executive Retirement Plan (d) OPEB Plans: PECO Energy Company Retiree Medical Plan (a) Exelon Corporation Health Care Program (a) Exelon Corporation Employees’ Life Insurance Plan (a) Exelon Corporation Health Reimbursement Arrangement Plan (a) Constellation Energy Group, Inc. Retiree Medical Plan (b) Constellation Energy Group, Inc. Retiree Dental Plan (b) Constellation Energy Group, Inc. Employee Life Insurance Plan and Family Life Insurance Plan (b) Constellation Mystic Power, LLC Post-Employment Medical Account Savings Plan (b) Exelon New England Union Post-Employment Medical Savings Account Plan (a) Retiree Medical Plan of Constellation Energy Nuclear Group, LLC (c) Retiree Dental Plan of Constellation Energy Nuclear Group, LLC (c) Nine Mile Point Nuclear Station, LLC Medical Care and Prescription Drug Plan for Retired Employees (c) Pepco Holdings LLC Welfare Plan for Retirees (d) __________ (a) These plans are collectively referred to as the legacy Exelon plans. (b) These plans are collectively referred to as the legacy Constellation Energy Group (CEG) Plans. (c) These plans are collectively referred to as the legacy CENG plans. (d) These plans are collectively referred to as the legacy PHI plans. Costs Allocation from Exelon We account for our participation in Exelon’s pension and OPEB plans by applying multi-employer accounting. Exelon allocates costs related to its pension and OPEB plans to its subsidiaries based on both active and retired employee participation in each plan. 125 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 15 — Retirement Benefits We were allocated pension and OPEB costs from Exelon of $ 123 million, $ 115 million, and $ 135 million for the years ended December 31, 2021, 2020, and 2019, respectively. We include the service cost and non-service cost components in Operating and maintenance expense and Property, plant, and equipment, net (where criteria for capitalization of direct labor has been met) in the consolidated financial statements. Contributions Exelon allocates contributions related to its legacy Exelon pension and OPEB plans to its subsidiaries based on accounting cost. For legacy CEG, CENG, FitzPatrick, and PHI plans, pension and OPEB contributions are allocated to the subsidiaries based on employee participation (both active and retired). The following tables provide our contributions to the pension and OPEB plans: Pension Benefits OPEB 2021 2020 2019 2021 2020 2019 $ 231 $ 236 $ 160 $ 28 $ 19 15 Exelon considers various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006 (the Act), management of the pension obligation, and regulatory implications. The Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification). The projected contributions below reflect a funding strategy to make levelized annual contributions with the objective of achieving 100% funded status on an Accumulated Benefit Obligation ("ABO") basis over time. This level funding strategy helps minimize volatility of future period required pension contributions. Unlike the qualified pension plans, Exelon’s non-qualified pension plans are not funded, given that they are not subject to statutory minimum contribution requirements. While OPEB plans are also not subject to statutory minimum contribution requirements, Exelon does fund certain of its plans. For Exelon's funded OPEB plans, contributions generally equal accounting costs, however, Exelon’s management has historically considered several factors in determining the level of contributions to its OPEB plans, including liabilities management, levels of benefit claims paid, and regulatory implications (amounts deemed prudent to meet regulatory expectations and best assure continued rate recovery). Defined Contribution Savings Plan We participate in various 401(k) defined contribution savings plans that are sponsored by Exelon. The plans are qualified under applicable sections of the IRC and allow employees to contribute a portion of their pre-tax and/or after-tax income in accordance with specified guidelines. We match a percentage of the employee contributions up to certain limits. The matching contributions to the savings plan were $ 53 million, $ 63 million, and $ 73 million for the years ended December 31, 2021, 2020, and 2019, respectively. Impact of Separation from Exelon Effective February 1, 2022, in connection with the separation, pension and OPEB obligations and the related plan assets for participants were transferred to pension and OPEB plans established by us as the plan sponsor. As the plan sponsor, effective with the first quarter of 2022, our Consolidated Balance Sheet will reflect an unfunded projected benefit obligation ("PBO") equal to an excess of the PBO over the fair value of the plan assets, consistent with a single employer benefit plan approach. We will no longer account for our participation in Exelon's pension and OPEB plans under the multi-employer benefit plan approach that has historically resulted in recognition of a net prepaid pension asset in our Consolidated Balance Sheets representing an excess of contributions over cumulative costs. In addition, we will be required to report the service cost and other non-service cost components of net periodic benefit costs for all plans separately in our Consolidated Statements of Operations and Comprehensive Income. Effective in the first quarter of 2022, the service cost component will be included in Operating and maintenance expense and Property, plant, and equipment, net (where criteria for capitalization of direct labor has been met) while the non-service cost components will be included in Other, net. 126 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 15 — Retirement Benefits We have also established various 401(k) defined contribution savings plans that are now sponsored by us. Refer to Note 24 — Separation from Exelon for additional details on the separation. The following table provides our planned contributions to our qualified pension plans, non-qualified pension plans, and OPEB plans in 2022 (including our benefit payments related to unfunded plans): Qualified Pension Plans Non-Qualified Pension Plans OPEB Planned contributions $ 192 $ 9 $ 11 16. Derivative Financial Instruments We use derivative instruments to manage commodity price risk, interest rate risk, and foreign exchange risk related to ongoing business operations. Authoritative guidance requires that derivative instruments be recognized as either assets or liabilities at fair value, with changes in fair value of the derivative recognized in earnings immediately. Other accounting treatments are available through special election and designation, provided they meet specific, restrictive criteria both at the time of designation and on an ongoing basis. These alternative permissible accounting treatments include NPNS, cash flow hedges, and fair value hedges. All derivative economic hedges related to commodities, referred to as economic hedges, are recorded at fair value through earnings. For all NPNS derivative instruments, accounts receivable or accounts payable are recorded when derivatives settle and revenue or expense is recognized in earnings as the underlying physical commodity is sold or consumed. Authoritative guidance about offsetting assets and liabilities requires the fair value of derivative instruments to be shown in the Notes to Consolidated Financial Statements on a gross basis, even when the derivative instruments are subject to legally enforceable master netting agreements and qualify for net presentation in the Consolidated Balance Sheets. A master netting agreement is an agreement between two counterparties that may have derivative and non-derivative contracts with each other providing for the net settlement of all referenced contracts via one payment stream, which takes place as the contracts deliver, when collateral is requested or in the event of default. In the tables below, which present fair value balances, our energy-related economic hedges and proprietary trading derivatives are shown gross. The impact of the netting of fair value balances with the same counterparty that are subject to legally enforceable master netting agreements, as well as netting of cash collateral, including margin on exchange positions, is aggregated in the collateral and netting columns. Our use of cash collateral is generally unrestricted unless we are downgraded below investment grade. Commodity Price Risk We employ established policies and procedures to manage our risks associated with market fluctuations in commodity prices by entering into physical and financial derivative contracts, including swaps, futures, forwards, options, and short-term and long-term commitments to purchase and sell energy and commodity products. We believe these instruments, which are either determined to be non-derivative or classified as economic hedges, mitigate exposure to fluctuations in commodity prices. To the extent the amount of energy we produce differs from the amount of energy we have contracted to sell, we are exposed to market fluctuations in the prices of electricity, fossil fuels, and other commodities. We use a variety of derivative and non-derivative instruments to manage the commodity price risk of our electric generation facilities, including power and gas sales, fuel and power purchases, natural gas transportation and pipeline capacity agreements, and other energy-related products marketed and purchased. To manage these risks, we may enter into fixed-price derivative or non-derivative contracts to hedge the variability in future cash flows from expected sales of power and gas and purchases of power and fuel. The objectives for executing such hedges include fixing the price for a portion of anticipated future electricity sales at a level that provides an acceptable return. We are also exposed to differences between the locational settlement prices of certain economic hedges and the hedged generating units. This price difference is actively managed through other instruments which include derivative congestion products, whose changes in fair value are recognized in earnings each period, and auction revenue rights, which are accounted for on an accrual basis. 127 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 16 — Derivative Financial Instruments Additionally, we are exposed to certain market risks through our proprietary trading activities. The proprietary trading activities are a complement to our energy marketing portfolio but represent a small portion of our overall energy marketing activities and are subject to limits established by the RMC. The following tables provide a summary of the derivative fair value balances recorded as of December 31, 2021 and 2020: December 31, 2021 Economic Hedges Proprietary Trading Collateral (a)(b) Netting (a) Total Mark-to-market derivative assets (current assets) $ 10,915 $ 25 $ 152 $ ( 8,923 ) $ 2,169 Mark-to-market derivative assets (noncurrent assets) 3,224 2 15 ( 2,298 ) 943 Total mark-to-market derivative assets 14,139 27 167 ( 11,221 ) 3,112 Mark-to-market derivative liabilities (current liabilities) ( 10,143 ) ( 19 ) 262 8,923 ( 977 ) Mark-to-market derivative liabilities (noncurrent liabilities) ( 2,893 ) ( 1 ) 83 2,298 ( 513 ) Total mark-to-market derivative liabilities ( 13,036 ) ( 20 ) 345 11,221 ( 1,490 ) Total mark-to-market derivative net assets (liabilities) $ 1,103 $ 7 $ 512 $ — $ 1,622 December 31, 2020 Mark-to-market derivative assets (current assets) $ 2,757 $ 40 $ 103 $ ( 2,261 ) $ 639 Mark-to-market derivative assets (noncurrent assets) 1,501 4 64 ( 1,015 ) 554 Total mark-to-market derivative assets 4,258 44 167 ( 3,276 ) 1,193 Mark-to-market derivative liabilities (current liabilities) ( 2,629 ) ( 23 ) 131 2,261 ( 260 ) Mark-to-market derivative liabilities (noncurrent liabilities) ( 1,335 ) ( 2 ) 118 1,015 ( 204 ) Total mark-to-market derivative liabilities ( 3,964 ) ( 25 ) 249 3,276 ( 464 ) Total mark-to-market derivative net assets (liabilities) $ 294 $ 19 $ 416 $ — $ 729 _________ (a) We net all available amounts allowed under the derivative authoritative guidance in the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases we may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and payables, transactions that do not qualify as derivatives, letters of credit and other forms of non-cash collateral. These amounts are not material as of December 31, 2021 and 2020 and not reflected in the table above. (b) Includes $ 897 million held and $ 209 million posted of variation margin on the exchanges as of December 31, 2021 and 2020, respectively. Economic Hedges (Commodity Price Risk) For the years ended December 31, 2021, 2020, and 2019, we recognized the following net pre-tax commodity mark-to-market gains (losses) which are also located in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows. Gain (Loss) Income Statement Location 2021 2020 2019 Operating revenues $ ( 635 ) $ 112 $ — Purchased power and fuel 1,206 168 ( 204 ) Total $ 571 $ 280 $ ( 204 ) In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on owned and contracted generation positions that have not been hedged. For merchant revenues not already hedged via comprehensive state programs, such as the CMC in Illinois, we utilize a three-year ratable sales plan to align our hedging strategy with our financial objectives. The prompt three-year merchant revenues are hedged on an approximate rolling 90%/60%/30% basis. We may also enter into transactions that are outside of this ratable hedging program. As of December 31, 2021, the percentage of expected generation hedged for the Mid- 128 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 16 — Derivative Financial Instruments Atlantic, Midwest, New York, and ERCOT reportable segments is 92 %- 95 % and 73 %- 76 % for 2022 and 2023, respectively. Proprietary Trading (Commodity Price Risk) We also execute commodity derivatives for proprietary trading purposes. Proprietary trading includes all contracts executed with the intent of benefiting from shifts or changes in market prices as opposed to those executed with the intent of hedging or managing risk. Gains and losses associated with proprietary trading are reported as Operating revenues in the Consolidated Statements of Operations and Comprehensive Income and are included in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows. For the years ended December 31, 2021, 2020, and 2019, net pre-tax commodity mark-to-market gains and losses were not material. Interest Rate and Foreign Exchange Risk We utilize interest rate swaps to manage our interest rate exposure and foreign currency derivatives to manage foreign exchange rate exposure associated with international commodity purchases in currencies other than U.S. dollars, both of which are treated as economic hedges. The notional amounts were $ 486 million and $ 665 million as of December 31, 2021 and 2020, respectively. The mark-to-market derivative assets and liabilities as of December 31, 2021 and 2020 and the mark-to-market gains and losses for the years ended December 31, 2021, 2020, and 2019 were not material. Credit Risk We would be exposed to credit-related losses in the event of non-performance by counterparties on executed derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts as of the reporting date. For commodity derivatives, we enter into enabling agreements that allow for payment netting with our counterparties, which reduces our exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. Typically, each enabling agreement is for a specific commodity and, with respect to each individual counterparty, netting is limited to t ransactions involving that specific commodity product, except where master netting agreements exist with a counterparty that allows for cross product netting. In addition to payment netting language in the enabling agreement, our credit department establishes credit limits, margining thresholds and collateral requirements for each counterparty, which are defined in the derivative contracts. Counterparty credit limits are based on an internal credit review process that considers a variety of factors, including the results of a scoring model, leverage, liquidity, profitability, credit ratings by credit rating agencies, and risk management capabilities. To the extent that a counterparty’s margining thresholds are exceeded, the counterparty is required to post collateral with us as specified in each enabling agreement. Our credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis. The following tables provide information on the credit exposure for all derivative instruments, NPNS and payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of December 31, 2021. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties. The amounts in the tables below exclude credit risk exposure from individual retail counterparties, nuclear fuel procurement contracts, and exposure through RTOs, ISOs, NYMEX, ICE, NASDAQ, NGX, and Nodal commodity exchanges. 129 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 16 — Derivative Financial Instruments Rating as of December 31, 2021 Total Exposure Before Credit Collateral Credit Collateral (a) Net Exposure Number of Counterparties Greater than 10% of Net Exposure Net Exposure of Counterparties Greater than 10% of Net Exposure Investment grade $ 715 $ 176 $ 539 1 $ 106 Non-investment grade 13 — 13 — — No external ratings Internally rated — investment grade 111 — 111 — — Internally rated — non-investment grade 226 47 179 — — Total $ 1,065 $ 223 $ 842 1 $ 106 Net Credit Exposure by Type of Counterparty As of December 31, 2021 Financial institutions $ 32 Investor-owned utilities, marketers, power producers 711 Energy cooperatives and municipalities 62 Other 37 Total $ 842 __________ (a) As of December 31, 2021, credit collateral held from counterparties where we had credit exposure included $ 163 million of cash and $ 60 million of letters of credit. The credit collateral does not include non-liquid collateral. Credit-Risk-Related Contingent Features As part of the normal course of business, we routinely enter into physically or financially settled contracts for the purchase and sale of electric capacity, electricity, fuels, emissions allowances, and other energy-related products. Certain of our derivative instruments contain provisions that require us to post collateral. We also enter into commodity transactions on exchanges where the exchanges act as the counterparty to each trade. Transactions on the exchanges must adhere to comprehensive collateral and margining requirements. This collateral may be posted in the form of cash or credit support with thresholds contingent upon our credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. These credit-risk related contingent features stipulate that if we were to be downgraded or lose our investment grade credit rating (based on our senior unsecured debt rating), we would be required to provide additional collateral. This incremental collateral requirement allows for the offsetting of derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master netting agreements. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. In this case, we believe an amount of several months of future payments (i.e., capacity payments) rather than a calculation of fair value is the best estimate for the contingent collateral obligation, which has been factored into the disclosure below. The aggregate fair value of all derivative instruments with credit-risk related contingent features in a liability position that are not fully collateralized (excluding transactions on the exchanges that are fully collateralized) is detailed in the table below: As of December 31, Credit-Risk Related Contingent Features 2021 2020 Gross fair value of derivative contracts containing this feature (a) $ ( 3,872 ) $ ( 834 ) Offsetting fair value of in-the-money contracts under master netting arrangements (b) 2,424 537 Net fair value of derivative contracts containing this feature (c) $ ( 1,448 ) $ ( 297 ) __________ (a) Amount represents the gross fair value of out-of-the-money derivative contracts containing credit-risk-related contingent features ignoring the effects of master netting agreements. 130 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 16 — Derivative Financial Instruments (b) Amount represents the offsetting fair value of in-the-money derivative contracts under legally enforceable master netting agreements with the same counterparty, which reduces the amount of any liability for which we could potentially be required to post collateral. (c) Amount represents the net fair value of out-of-the-money derivative contracts containing credit-risk related contingent features after considering the mitigating effects of offsetting positions under master netting arrangements and reflects the actual net liability upon which any potential contingent collateral obligations would be based. As of December 31, 2021 and 2020, we posted or held the following amounts of cash collateral and letters of credit on derivative contracts with external counterparties, after giving consideration to offsetting derivative and non-derivative positions under master netting agreements. As of December 31, 2021 2020 Cash collateral posted $ 713 $ 511 Letters of credit posted 755 226 Cash collateral held 182 110 Letters of credit held 124 40 Additional collateral required in the event of a credit downgrade below investment grade 2,113 1,432 We entered into supply forward contracts with certain utilities with one-sided collateral postings only from us. If market prices fall below the benchmark price levels in these contracts, the utilities are not required to post collateral. However, when market prices rise above the benchmark price levels, counterparty suppliers, including us, are required to post collateral once certain unsecured credit limits are exceeded. 17. Debt and Credit Agreements Short-Term Borrowings We meet our short-term liquidity requirements primarily through the issuance of commercial paper. We may use our credit facility for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit. Commercial Paper The following table reflects our commercial paper program supported by the revolving credit agreements and bilateral credit agreements as of December 31, 2021 and 2020: Maximum Program Size at December 31, Outstanding Commercial Paper at December 31, Average Interest Rate on Commercial Paper Borrowings at December 31, 2021 (a)(b) 2020 (a)(b) 2021 2020 2021 2020 $ 5,300 $ 5,300 $ 702 $ 340 0.66 % 0.27 % __________ (a) Excludes $ 1,200 million and $ 1,500 million in bilateral credit facilities as of December 31, 2021 and 2020, respectively, and $ 131 million and $ 144 million in credit facilities for project finance as of December 31, 2021 and 2020, respectively. These credit facilities do not back our commercial paper program. (b) As of December 31, 2021, excludes $ 44 million of credit facility agreements arranged at minority and community banks. These facilities expire on October 7, 2022 and are solely utilized to issue letters of credit. As of December 31, 2020, excludes $ 38 million of credit facility agreements arranged at minority and community banks. In order to maintain our commercial paper program in the amounts indicated above, we must have a credit facility in place, at least equal to the amount of our commercial paper program. We do not issue commercial paper in an aggregate amount exceeding the then available capacity under our credit facility. 131 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 17 — Debt and Credit Agreements As of December 31, 2021, we had the following aggregate bank commitments, credit facility borrowings and available capacity under our respective credit facilities: Available Capacity as of December 31, 2021 Facility Type Aggregate Bank Commitment (b) Facility Draws Outstanding Letters of Credit Actual To Support Additional Commercial Paper Syndicated Revolver (a) $ 5,300 $ — $ 1,230 $ 4,070 $ 3,368 Bilaterals 1,200 — 1,029 171 — Project Finance 131 — 116 15 — __________ (a) Our syndicated revolving credit facility was replaced by the $ 3.5 billion 5-year revolving credit agreement entered into on February 1, 2022 in connection with our separation. (b) Excludes $ 44 million of credit facility agreements arranged at minority and community banks. These facilities expire on October 7, 2022 and are solely utilized to issue letters of credit. As of December 31, 2021, letters of credit issued under these facilities totaled $ 5 million. Impact of Separation from Exelon In connection with our separation from Exelon, we entered into two new credit agreements that replaced our $ 5.3 billion syndicated revolving credit facility, On February 1, 2022, we entered into a new credit agreement establishing a $ 3.5 billion five-year revolving credit facility at a variable interest rate of SOFR plus 1.275 % and on February 9, 2022 we entered into a $ 1 billion five-year liquidity facility with the primary purpose of supporting our letter of credit issuances. Many of our bilateral credit agreements remain in effect. See below for additional details. Bilateral Credit Agreements The following table reflects the bilateral credit agreements at December 31, 2021: Date Initiated Latest Amendment Date Maturity Date(a) Amount January 11, 2013 (b)(c) March 1, 2021 March 1, 2023 $ 100 January 5, 2016 (b) April 2, 2021 April 5, 2023 150 February 21, 2019 (b)(c) March 31, 2021 March 31, 2022 100 October 25, 2019 (b) N/A N/A 200 November 20, 2019 (b) N/A N/A 300 November 21, 2019 (b) N/A N/A 150 November 21, 2019 (b) November 21, 2021 November 21, 2022 100 May 15, 2020 (b)(d) N/A N/A 100 __________ (a) Credit facilities that do not contain a maturity date are specific to the agreements set within each contract. In some instances, credit facilities are automatically renewed based on the contingency standards set within the specific agreement. (b) Bilateral credit agreements solely support the issuance of letters of credit and do not back our commercial paper program. (c) The bilateral credit agreement was terminated on January 31, 2022. (d) On February 9, 2022, the bilateral credit agreement increased to $ 200 million. Borrowings under our revolving credit agreement bear interest at a rate based upon either the prime rate or a LIBOR-based rate, plus an adder based upon our credit rating. The adders for the prime based borrowings and LIBOR-based borrowings are 27.5 basis points and 127.5 basis points, respectively. If we lose our investment grade rating, the maximum adders for prime rate borrowings and LIBOR-based rate borrowings would be 65 basis points and 165 basis points, respectively. The credit agreements also require the borrower to pay a facility fee based upon the aggregate commitments. The fee varies depending upon the respective credit ratings of the borrower. 132 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 17 — Debt and Credit Agreements Short-Term Loan Agreements On March 19, 2020, we entered into a term loan agreement for $ 200 million. The loan agreement was renewed on March 17, 2021 and will expire on March 16, 2022. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.875 % and all indebtedness thereunder is unsecured. The loan agreement is reflected in Short-term borrowings in the Consolidated Balance Sheet. In connection with the separation, we repaid the term loan on January 26, 2022. See Note 24 — Separation from Exelon for additional information On March 31, 2020, we entered into a term loan agreement for $ 300 million. The loan agreement was renewed on March 30, 2021 and will expire on March 29, 2022. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.70 % and all indebtedness thereunder is unsecured. The loan agreement is reflected in Short-term borrowings in the Consolidated Balance Sheet. On August 6, 2021, we entered into a 364-day term loan agreement for $ 880 million to fund the purchase of EDF's equity interest in CENG. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate of LIBOR plus 0.875 % until March 31, 2022 and a rate of LIBOR plus 1 % thereafter and all indebtedness thereunder is unsecured. The loan agreement is reflected in Short-term borrowings in the Consolidated Balance Sheet. The loan agreement was amended on January 24, 2022 to change the maturity date to June 30, 2022 from August 5, 2022. See Note 2 — Mergers, Acquisitions, and Dispositions for additional information. Long-Term Debt The following table presents the outstanding long-term debt as of December 31, 2021 and 2020: Maturity Date December 31, Rates 2021 2020 Long-term debt Senior unsecured notes 3.25 % - 7.60 % 2022 - 2042 $ 4,219 $ 4,219 Notes payable and other 2.10 % - 4.85 % 2022 - 2028 103 111 Nonrecourse debt: Fixed rates 2.29 % - 6.00 % 2031 - 2037 909 977 Variable rates 2.98 % - 3.50 % 2026 - 2027 870 765 Total long-term debt 6,101 6,072 Unamortized debt discount and premium, net ( 7 ) ( 5 ) Unamortized debt issuance costs ( 42 ) ( 46 ) Fair value adjustment 62 66 Long-term debt due within one year ( 1,220 ) ( 197 ) Long-term debt $ 4,894 $ 5,890 Long-term debt maturities in the periods 2022 through 2026 and thereafter are as follows: 2022 $ 1,220 2023 1 2024 1 2025 901 2026 114 Thereafter 3,864 Total $ 6,101 Long-Term Debt from Affiliates 133 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 17 — Debt and Credit Agreements In connection with the debt obligations assumed by Exelon as part of the 2012 merger, Exelon and our subsidiaries assumed intercompany loan agreements that mirror the terms and amounts of the third-party debt obligations of Exelon, resulting in intercompany notes payable to Exelon Corporate. As of December 31, 2021 and 2020, we had $ 319 million and $ 324 million, respectively, recorded to intercompany notes payable to Exelon Corporate. In connection with the separation, on January 31, 2022, we paid cash to Exelon Corporate in the amount of $ 258 million to settle the intercompany loan. See Note 24 — Separation from Exelon for additional information. Debt Covenants As of December 31, 2021, we are in compliance with debt covenants. Nonrecourse Debt We have also issued nonrecourse debt, for which approximately $ 2 billion of generating assets have been pledged as collateral as of December 31, 2021. Borrowings under these agreements are secured by the assets and equity of each respective project. The lenders do not have recourse against us in the event of a default. If a specific project financing entity does not maintain compliance with its specific nonrecourse debt covenants, there could be a requirement to accelerate repayment of the associated debt or other borrowings earlier than the stated maturity dates. In these instances, if such repayment was not satisfied, the lenders or security holders would generally have rights to foreclose against the project-specific assets and related collateral. The potential requirement to satisfy the associated debt or other borrowings earlier than otherwise anticipated could lead to impairments due to a higher likelihood of disposing of the respective project-specific assets significantly before the end of their useful lives. Antelope Valley Solar Ranch One. In December 2011, the DOE Loan Programs Office issued a guarantee for up to $ 646 million for a nonrecourse loan from the Federal Financing Bank to support the financing of the construction of the Antelope Valley facility. The project became fully operational in 2014. The loan will mature on January 5, 2037. Interest rates on the loan were fixed upon each advance at a spread of 37.5 basis points above U.S. Treasuries of comparable maturity. The advances were completed as of December 31, 2015 and the outstanding loan balance will bear interest at an average blended interest rate of 2.82 %. As of December 31, 2021 and 2020, approximately $ 435 million and $ 460 million were outstanding, respectively. In addition, we have issued letters of credit to support the equity investment in the project, with $ 37 million outstanding as of December 31, 2021. In December 2017, our interests in Antelope Valley were contributed to and are pledged as collateral for the CR financing structures referenced below. Continental Wind, LLC. In September 2013, Continental Wind, our indirect subsidiary, completed the issuance and sale of $ 613 million senior secured notes. Continental Wind owns and operates a portfolio of wind farms in Idaho, Kansas, Michigan, Oregon, New Mexico and Texas with a total net capacity of 667 MW. The net proceeds were distributed to us for general business purposes. The notes are scheduled to mature on February 28, 2033. The notes bear interest at a fixed rate of 6.00 % with interest payable semi-annually. As of December 31, 2021 and December 31, 2020, approximately $ 380 million and $ 415 million were outstanding, respectively. In addition, Continental Wind has a $ 122 million letter of credit facility and $ 4 million working capital revolver facility. Continental Wind has issued letters of credit to satisfy certain of its credit support and security obligations. As of December 31, 2021, the Continental Wind letter of credit facility had $ 115 million in letters of credit outstanding related to the project. In 2017, our interests in Continental Wind were contributed to CRP. Refer to Note 21 - Variable Interest Entities for additional information on CRP. Renewable Power Generation. In March 2016, RPG, our indirect subsidiary, issued $ 150 million aggregate principal amount of nonrecourse senior secured notes. The net proceeds were distributed to us for paydown of long term debt obligations at Sacramento PV Energy and Constellation Solar Horizons and for general business purposes. The loan is scheduled to mature on March 31, 2035. The term loan bears interest at a fixed rate of 4.11 % payable semi-annually. As of December 31, 2021 and December 31, 2020, approximately $ 90 million and $ 95 million were outstanding, respectively. In 2017, our interests in RPG were contributed to CRP. Refer to Note 21 - Variable Interest Entities for additional information on CRP. 134 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 17 — Debt and Credit Agreements SolGen, LLC. In September 2016, SolGen, an indirect subsidiary, issued $ 150 million aggregate principal amount of nonrecourse senior secured notes. The net proceeds were distributed to us for general business purposes. On December 8, 2020, we entered into agreement with an affiliate of Brookfield Renewable, for the sale of a significant portion of our solar business. The sale was completed on March 31, 2021 in which the buyer assumed the $ 125 million outstanding debt. See Note 2 — Mergers, Acquisitions, and Dispositions for additional information on the sale agreement. Constellation Renewables. In November 2017, CR, our indirect subsidiary, entered into an $ 850 million nonrecourse senior secured term loan credit facility agreement with a maturity date of November 28, 2024. In addition to the financing, CR entered into interest rate swaps with an initial notional amount of $ 636 million at an interest rate of 2.32 % to manage a portion of the interest rate exposure in connection with the financing. In December 2020, CR entered into a financing agreement for a $ 750 million nonrecourse senior secured term loan credit facility, scheduled to mature on December 15, 2027. The term loan bears interest at a variable rate equal to LIBOR plus 2.50 %, subject to a 1 % LIBOR floor with interest payable quarterly. In addition to the financing, CR entered into interest rate swaps with an initial notional amount of $ 516 million at an interest rate of 1.05 % to manage a portion of the interest rate exposure in connection with the financing. The proceeds were used to repay the November 2017 nonrecourse senior secured term loan credit facility of $ 850 million, of which $ 709 million was outstanding as of the retirement date in December of 2020, and to settle the November 2017 interest rate swap. Our interests in CRP and Antelope Valley remain contributed to and pledged as collateral for this financing. As of December 31, 2021 and December 31, 2020, $ 735 million and $ 750 million was outstanding, respectively. See Note 21 — Variable Interest Entities for additional information on CRP and Note 16 — Derivative Financial Instruments for additional information on interest rate swaps. West Medway II, LLC. On May 13, 2021, West Medway II, LLC (West Medway II), our indirect subsidiary, entered into a financing agreement for a $ 150 million nonrecourse senior secured term loan credit facility with a maturity date of March 31, 2026. The term loan bears interest at an average blended interest rate of LIBOR plus 3 %, paid quarterly. In addition to the financing, West Medway II, entered into interest rate swaps with an initial notional amount of $ 113 million at an interest rate of 0.61 %, paid quarterly, to manage a portion of the interest rate exposure in connection with the financing. We used the net proceeds for general corporate purposes. Our interests in West Medway II, were pledged as collateral for this financing. As of December 31, 2021, approximately $ 135 million was outstanding. See Note 16 — Derivative Financial Instruments for additional information on interest rate swaps. 18. Fair Value of Financial Assets and Liabilities We measure and classify fair value measurements in accordance with the hierarchy as defined by GAAP. The hierarchy prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows: • Level 1 — quoted prices (unadjusted) in active markets for identical assets or liabilities that we have the ability to liquidate as of the reporting date. • Level 2 — inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data. • Level 3 — unobservable inputs, such as internally developed pricing models or third-party valuations for the asset or liability due to little or no market activity for the asset or liability. 135 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 18 — Fair Value of Financial Assets and Liabilities Fair Value of Financial Liabilities Recorded at Amortized Cost The following tables present the carrying amounts and fair values of the short-term liabilities, long-term debt, and the SNF obligation as of December 31, 2021 and 2020. We have no financial liabilities classified as Level 1. The carrying amounts of the short-term liabilities as presented in the Consolidated Balance Sheets are representative of their fair value (Level 2) because of the short-term nature of these instruments. December 31, 2021 December 31, 2020 Carrying Amount Fair Value Carrying Amount Fair Value Level 2 Level 3 Total Level 2 Level 3 Total Long-Term Debt, including amounts due within one year $ 6,114 $ 5,749 $ 1,093 $ 6,842 $ 6,087 $ 5,648 $ 1,208 $ 6,856 SNF Obligation 1,210 1,060 — 1,060 1,208 909 — 909 We use the following methods and assumptions to estimate fair value of financial liabilities recorded at carrying cost: Type Level Valuation Long-term Debt, including amounts due within one year Taxable Debt Securities 2 The fair value is determined by a valuation model that is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. We obtain credit spreads based on trades of our existing debt securities as well as other issuers in the utility sector with similar credit ratings. The yields are then converted into discount rates of various tenors that are used for discounting the respective cash flows of the same tenor for each bond or note. Variable Rate Financing Debt 2 Debt rates are reset on a regular basis and the carrying value approximates fair value. Government Backed Fixed Rate Project Financing Debt 3 The fair value is similar to the process for taxable debt securities. Due to the lack of market trading data on similar debt, the discount rates are derived based on the original loan interest rate spread to the applicable U.S. Treasury rate as well as a current market curve derived from government-backed securities. Non-Government Backed Fixed Rate Nonrecourse Debt 3 Fair value is based on market and quoted prices for its own and other nonrecourse debt with similar risk profiles. Given the low trading volume in the nonrecourse debt market, the price quotes used to determine fair value will reflect certain qualitative factors, such as market conditions, investor demand, new developments that might significantly impact the project cash flows or off-taker credit, and other circumstances related to the project. SNF Obligation SNF Obligation 2 The carrying amount is derived from a contract with the DOE to provide for disposal of SNF from certain of our nuclear generating stations. See Note 19 — Commitments and Contingencies for further details. When determining the fair value of the obligation, the future carrying amount of the SNF obligation is calculated by compounding the current book value of the SNF obligation at the 13-week U.S. Treasury rate. The compounded obligation amount is discounted back to present value using our discount rate, which is calculated using the same methodology as described above for the taxable debt securities, and an estimated maturity date of 2035. 136 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 18 — Fair Value of Financial Assets and Liabilities Recurring Fair Value Measurements The following tables present assets and liabilities measured and recorded at fair value in the Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2021 and 2020: 137 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 18 — Fair Value of Financial Assets and Liabilities As of December 31, 2021 As of December 31, 2020 Level 1 Level 2 Level 3 Not subject to leveling Total Level 1 Level 2 Level 3 Not subject to leveling Total Assets Cash equivalents (a) $ 113 $ — $ — $ — $ 113 $ 124 $ — $ — $ — $ 124 NDT fund investments Cash equivalents (b) 465 116 — — 581 210 95 — — 305 Equities 4,564 1,805 — 1,645 8,014 3,886 2,077 — 1,562 7,525 Fixed income Corporate debt (c) — 1,145 286 — 1,431 — 1,485 285 — 1,770 U.S. Treasury and agencies 2,193 30 — — 2,223 1,871 126 — — 1,997 Foreign governments — 60 — — 60 — 56 — — 56 State and municipal debt — 26 — — 26 — 101 — — 101 Other 29 23 — 1,449 1,501 — 41 — 961 1,002 Fixed income subtotal 2,222 1,284 286 1,449 5,241 1,871 1,809 285 961 4,926 Private credit — — 178 624 802 — — 212 629 841 Private equity — — — 673 673 — — — 504 504 Real estate — — — 864 864 — — — 679 679 NDT fund investments subtotal (d)(e) 7,251 3,205 464 5,255 16,175 5,967 3,981 497 4,335 14,780 Rabbi trust investments Cash equivalents 3 — — — 3 4 — — — 4 Mutual funds 36 — — — 36 29 — — — 29 Life insurance contracts — 33 — — 33 — 28 — — 28 Rabbi trust investments subtotal 39 33 — — 72 33 28 — — 61 Investments in equities (f) 43 — — — 43 195 — — — 195 Commodity derivative assets Economic hedges 3,017 7,223 3,899 — 14,139 745 1,914 1,599 — 4,258 Proprietary trading — 19 8 — 27 — 17 27 — 44 Effect of netting and allocation of collateral (g)(h) ( 2,108 ) ( 6,177 ) ( 2,769 ) — ( 11,054 ) ( 607 ) ( 1,597 ) ( 905 ) — ( 3,109 ) Commodity derivative assets subtotal 909 1,065 1,138 — 3,112 138 334 721 — 1,193 DPP consideration — 365 — — 365 — 639 — — 639 Total assets 8,355 4,668 1,602 5,255 19,880 6,457 4,982 1,218 4,335 16,992 Liabilities Commodity derivative liabilities Economic hedges ( 2,201 ) ( 6,870 ) ( 3,965 ) — ( 13,036 ) ( 682 ) ( 1,928 ) ( 1,354 ) — ( 3,964 ) Proprietary trading — ( 18 ) ( 2 ) — ( 20 ) — ( 21 ) ( 4 ) — ( 25 ) Effect of netting and allocation of collateral (g)(h) 2,189 6,642 2,735 — 11,566 540 1,918 1,067 — 3,525 Commodity derivative liabilities subtotal ( 12 ) ( 246 ) ( 1,232 ) — ( 1,490 ) ( 142 ) ( 31 ) ( 291 ) — ( 464 ) Deferred compensation obligation — ( 43 ) — — ( 43 ) — ( 42 ) — — ( 42 ) Total liabilities ( 12 ) ( 289 ) ( 1,232 ) — ( 1,533 ) ( 142 ) ( 73 ) ( 291 ) — ( 506 ) Total net assets $ 8,343 $ 4,379 $ 370 $ 5,255 $ 18,347 $ 6,315 $ 4,909 $ 927 $ 4,335 $ 16,486 138 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 18 — Fair Value of Financial Assets and Liabilities __________ (a) We exclude cash of $ 417 million and $ 171 million as of December 31, 2021 and 2020, respectively, and restricted cash of $ 46 million and $ 20 million as of December 31, 2021 and 2020, respectively. (b) Includes $ 116 million of cash received from outstanding repurchase agreements as of both December 31, 2021 and 2020, and is offset by an obligation to repay upon settlement of the agreement as discussed in (e) below. (c) Includes investments in equities sold short of $( 55 ) million and $( 62 ) million as of December 31, 2021 and 2020, respectively, held in an investment vehicle primarily to hedge the equity option component of convertible debt. (d) Includes net derivative liabilities of $ 1 million and net derivative assets of $ 2 million, which have total notional amounts of $ 687 million and $ 1,043 million as of December 31, 2021 and 2020, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the periods ended and do not represent the amount of our exposure to credit or market loss. (e) Excludes net liabilities of $ 111 million and $ 181 million as of December 31, 2021 and 2020, respectively, which include certain derivative assets that have notional amounts of $ 182 million and $ 104 million as of December 31, 2021 and 2020, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, repurchase agreement obligations, and payables related to pending securities purchases. The repurchase agreements are generally short-term in nature with durations generally of 30 days or less. (f) Includes equity investments which were previously designated as equity investments without readily determinable fair values but are now publicly traded and therefore have readily determinable fair values. The first investment became publicly traded in the fourth quarter of 2020. The fair value of these investments is recorded in Other current assets in the Consolidated Balance Sheets based on the quoted market prices of the stocks as of the respective balance sheet date. Unrealized (losses)/gains of $( 160 ) million and $ 186 million were recorded in Other, net in the Consolidated Statement of Operations and Comprehensive Income for the years ended December 31, 2021 and 2020, respectively. (g) Collateral posted/(received) from counterparties, net of collateral paid to counterparties, totaled $ 81 million, $ 465 million, and $( 34 ) million allocated to Level 1, Level 2, and Level 3 mark-to-market derivatives, respectively, as of December 31, 2021. Collateral posted/(received) from counterparties, net of collateral paid to counterparties, totaled $( 67 ) million, $ 321 million, and $ 162 million allocated to Level 1, Level 2, and Level 3 mark-to-market derivatives, respectively, as of December 31, 2020. (h) Includes $ 897 million held and $ 209 million posted of variation margin with the exchanges as of December 31, 2021 and 2020, respectively. As of December 31, 2021, we have outstanding commitments to invest in private credit, private equity, and real estate investments of $ 306 million, $ 171 million, and $ 459 million, respectively. These commitments will be funded by our existing NDT funds. We hold investments without readily determinable fair values with carrying amounts of $ 33 million and $ 55 million as of December 31, 2021 and 2020, respectively. Changes in fair value, cumulative adjustments, and impairments were not material for the years ended December 31, 2021 and 2020. Reconciliation of Level 3 Assets and Liabilities The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the years ended December 31, 2021 and 2020: 139 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 18 — Fair Value of Financial Assets and Liabilities For the Year Ended December 31, 2021 NDT Fund Investments Mark-to-Market Derivatives Total Balance as of January 1, 2021 $ 497 $ 430 $ 927 Total realized / unrealized gains (losses) Included in net income 5 ( 812 ) (a) ( 807 ) Included in noncurrent payables to affiliates 19 — 19 Change in collateral — ( 196 ) ( 196 ) Purchases, sales, issuances and settlements Purchases 4 162 166 Sales — ( 10 ) ( 10 ) Settlements ( 61 ) — ( 61 ) Transfers into Level 3 — 19 (b) 19 Transfers out of Level 3 — 313 (b) 313 Balance as of December 31, 2021 $ 464 $ ( 94 ) $ 370 The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of December 31, 2021 $ 5 $ ( 1,222 ) $ ( 1,217 ) For the Year Ended December 31, 2020 NDT Fund Investments Mark-to-Market Derivatives Total Balance as of January 1, 2020 $ 511 $ 817 $ 1,328 Total realized / unrealized gains (losses) Included in net income 2 ( 414 ) (a) ( 412 ) Included in noncurrent payables to affiliates 21 — 21 Change in collateral — ( 53 ) ( 53 ) Purchases, sales, issuances and settlements Purchases 8 143 151 Sales — ( 27 ) ( 27 ) Settlements ( 45 ) — ( 45 ) Transfers into Level 3 — ( 12 ) (b) ( 12 ) Transfers out of Level 3 — ( 24 ) (b) ( 24 ) Balance as of December 31, 2020 $ 497 $ 430 $ 927 The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of December 31, 2020 $ 2 $ 6 $ 8 __________ (a) Includes an addition of $ 410 million for realized losses and a reduction of $ 420 million for realized gains due to the settlement of derivative contracts for the years ended December 31, 2021 and 2020, respectively. (b) Transfers into and out of Level 3 generally occur when the contract tenor becomes less and more observable, respectively, primarily due to changes in market liquidity or assumptions for certain commodity contracts. The following table presents the income statement classification of the total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis during the years ended December 31, 2021 and 2020: 140 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 18 — Fair Value of Financial Assets and Liabilities Operating Revenues Purchased Power and Fuel Other, net Total (losses) gains included in net income for the year ended December 31, 2021 $ ( 1,343 ) $ 531 $ 5 Total unrealized (losses) gains for the year ended December 31, 2021 ( 1,577 ) 355 5 Total (losses) gains included in net income for the year ended December 31, 2020 $ ( 404 ) $ ( 10 ) $ 2 Total unrealized (losses) gains for the year ended December 31, 2020 ( 31 ) 37 2 Valuation Techniques Used to Determine Fair Value Cash Equivalents. Investments with original maturities of three months or less when purchased, including mutual and money market funds, are considered cash equivalents. The fair values are based on observable market prices and, therefore, are included in the recurring fair value measurements hierarchy as Level 1. NDT Fund Investments. The trust fund investments have been established to satisfy our nuclear decommissioning obligations as required by the NRC. The NDT funds hold debt and equity securities directly and indirectly through commingled funds and mutual funds, which are included in equities and fixed income. Our NDT fund investments policies outline investment guidelines for the trusts and limit the trust funds’ exposures to investments in highly illiquid markets and other alternative investments, including private credit, private equity, and real estate. Investments with maturities of three months or less when purchased, including certain short-term fixed income securities are considered cash equivalents and included in the recurring fair value measurements hierarchy as Level 1 or Level 2. Equities. These investments consist of individually held equity securities, equity mutual funds, and equity commingled funds in domestic and foreign markets. With respect to individually held equity securities, the trustees obtain prices from pricing services, whose prices are generally obtained from direct feeds from market exchanges, which we are able to independently corroborate. Equity securities held individually, including real estate investment trusts, rights, and warrants, are primarily traded on exchanges that contain only actively traded securities due to the volume trading requirements imposed by these exchanges. The equity securities that are held directly by the trust funds are valued based on quoted prices in active markets and categorized as Level 1. Certain equity securities have been categorized as Level 2 because they are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities. Certain private placement equity securities are categorized as Level 3 because they are not publicly traded and are priced using significant unobservable inputs. Equity commingled funds and mutual funds are maintained by investment companies, and fund investments are held in accordance with a stated set of fund objectives. The values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets and have been categorized as Level 1. For equity commingled funds and mutual funds which are not publicly quoted, the fund administrators value the funds using the NAV per fund share, derived from the quoted prices in active markets on the underlying securities and are not classified within the fair value hierarchy. These investments can typically be redeemed monthly or more frequently, with 30 or less days of notice and without further restrictions. Fixed income. For fixed income securities, which consist primarily of corporate debt securities, U.S. government securities, foreign government securities, municipal bonds, asset and mortgage-backed securities, commingled funds, mutual funds, and derivative instruments, the trustees obtain multiple prices from pricing vendors whenever possible, which enables cross-provider validations in addition to checks for unusual daily movements. A primary price source is identified based on asset type, class, or issue for each security. With respect to individually held fixed income securities, the trustees monitor prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the portfolio managers challenge an assigned price and the trustees determine that another price source is considered to be preferable. We have obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, we selectively corroborate the fair values of securities by comparison to other market-based price sources. Investments in U.S. Treasury securities have been categorized 141 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 18 — Fair Value of Financial Assets and Liabilities as Level 1 because they trade in highly-liquid and transparent markets. Certain private placement fixed income securities have been categorized as Level 3 because they are priced using certain significant unobservable inputs and are typically illiquid. The remaining fixed income securities, including certain other fixed income investments, are based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences and are categorized as Level 2. Other fixed income investments primarily consist of fixed income commingled funds and mutual funds, which are maintained by investment companies and hold fund investments in accordance with a stated set of fund objectives. The values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets and have been categorized as Level 1. For fixed income commingled funds and mutual funds which are not publicly quoted, the fund administrators value the funds using the NAV per fund share, derived from the quoted prices in active markets of the underlying securities and are not classified within the fair value hierarchy. These investments typically can be redeemed monthly or more frequently, with 30 or less days of notice and without further restrictions. Derivative instruments. These instruments, consisting primarily of futures and swaps to manage risk, are recorded at fair value. Over-the-counter derivatives are valued daily, based on quoted prices in active markets and trade in open markets, and have been categorized as Level 1. Derivative instruments other than over-the-counter derivatives are valued based on external price data of comparable securities and have been categorized as Level 2. Private credit. Private credit investments primarily consist of investments in private debt strategies. These investments are generally less liquid assets with an underlying term of 3 to 5 years and are intended to be held to maturity. The fair value of these investments is determined by the fund manager or administrator using a combination of valuation models including cost models, market models, and income models and typically cannot be redeemed until maturity of the term loan. Private credit investments held directly by us are categorized as Level 3 because they are based largely on inputs that are unobservable and utilize complex valuation models. For managed private credit funds, the fair value is determined using a combination of valuation models including cost models, market models, and income models and typically cannot be redeemed until maturity of the term loan. Managed private credit fund investments are not classified within the fair value hierarchy because their fair value is determined using NAV or its equivalent as a practical expedient. Private equity. These investments include those in limited partnerships that invest in operating companies that are not publicly traded on a stock exchange such as leveraged buyouts, growth capital, venture capital, distressed investments, and investments in natural resources. These investments typically cannot be redeemed and are generally liquidated over a period of 8 to 10 years from the initial investment date, which is based on our understanding of the investment funds. Private equity valuations are reported by the fund manager and are based on the valuation of the underlying investments, which include unobservable inputs such as cost, operating results, discounted future cash flows, and market based comparable data. These valuation inputs are unobservable. The fair value of private equity investments is determined using NAV or its equivalent as a practical expedient, and therefore, these investments are not classified within the fair value hierarchy. Real estate. These investments are funds with a direct investment in pools of real estate properties. These funds are reported by the fund manager and are generally based on independent appraisals of the underlying investments from sources with professional qualifications, typically using a combination of market based comparable data and discounted cash flows. These valuation inputs are unobservable. Certain real estate investments cannot be redeemed and are generally liquidated over a period of 8 to 10 years from the initial investment date, which is based on our understanding of the investments funds. The remaining liquid real estate investments are generally redeemable from the investment vehicle quarterly, with 30 to 90 days of notice. The fair value of real estate investments is determined using NAV or its equivalent as a practical expedient, and therefore, these investments are not classified within the fair value hierarchy. We evaluated our NDT portfolios for the existence of significant concentrations of credit risk as of December 31, 2021. Types of concentrations that were evaluated include, but are not limited to, investment concentrations in a single entity, type of industry, foreign country, and individual fund. As of December 31, 2021, there were no significant concentrations (generally defined as greater than 10 percent) of risk in the NDT assets. See Note 10 — Asset Retirement Obligations for additional information on the NDT fund investments. 142 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 18 — Fair Value of Financial Assets and Liabilities Rabbi Trust Investments. The Rabbi trusts were established to hold assets related to deferred compensation plans existing for certain active and retired members of executive management and directors. The Rabbi trusts' assets are included in investments in the Consolidated Balance Sheets and consist primarily of money market funds, mutual funds, and life insurance policies. Money market funds and mutual funds are publicly quoted and have been categorized as Level 1 given the clear observability of the prices. The life insurance policies are valued using the cash surrender value of the policies, net of loans against those policies, which is provided by a third-party. Certain life insurance policies, which consist primarily of mutual funds that are priced based on observable market data, have been categorized as Level 2 because the life insurance policies can be liquidated at the reporting date for the value of the underlying assets. Deferred Compensation Obligations. Our deferred compensation plans allow participants to defer certain cash compensation into a notional investment account. We include such plans in other current and noncurrent liabilities in the Consolidated Balance Sheets. The value of our deferred compensation obligations is based on the market value of the participants’ notional investment accounts. The underlying notional investments are comprised primarily of equities, mutual funds, commingled funds, and fixed income securities which are based on directly and indirectly observable market prices. Since the deferred compensation obligations themselves are not exchanged in an active market, they are categorized as Level 2 in the fair value hierarchy. The value of certain employment agreement obligations (which are included with the Deferred Compensation Obligation in the table above) are based on a known and certain stream of payments to be made over time and are categorized as Level 2 within the fair value hierarchy. Investments in Equities. We hold certain investments in equity securities with readily determinable fair values in addition to those held within the NDT funds. These equity securities are valued based on quoted prices in active markets and are categorized as Level 1. Deferred Purchase Price Consideration. We have DPP consideration for the sale of certain receivables of retail electricity. This amount is valued based on the sales price of the receivables net of allowance for credit losses based on accounts receivable aging historical experience coupled with specific identification through a credit monitoring process, which considers current conditions and forward-looking information such as industry trends, macroeconomic factors, changes in the regulatory environment, external credit ratings, publicly available news, payment status, payment history, and the exercise of collateral calls. Since the DPP consideration is based on the sales price of the receivables, it is categorized as Level 2 in the fair value hierarchy. See Note 6 — Accounts Receivable for additional information on the sale of certain receivables. Mark-to-Market Derivatives. Derivative contracts are traded in both exchange-based and non-exchange-based markets. Exchange-based derivatives that are valued using unadjusted quoted prices in active markets are categorized in Level 1 in the fair value hierarchy. Certain derivatives’ pricing is verified using indicative price quotations available through brokers or over-the-counter, on-line exchanges and are categorized in Level 2. These price quotations reflect the average of the bid-ask, mid-point prices and are obtained from sources that we believe provide the most liquid market for the commodity. The price quotations are reviewed and corroborated to ensure the prices are observable and representative of an orderly transaction between market participants. This includes consideration of actual transaction volumes, market delivery points, bid-ask spreads, and contract duration. The remainder of derivative contracts are valued using the Black model, an industry standard option valuation model. The Black model takes into account inputs such as contract terms, including maturity, and market parameters, including assumptions of the future prices of energy, interest rates, volatility, credit worthiness, and credit spread. For derivatives that trade in liquid markets, such as generic forwards, swaps, and options, model inputs are generally observable. Such instruments are categorized in Level 2. Our derivatives are predominantly at liquid trading points. For derivatives that trade in less liquid markets with limited pricing information, model inputs generally would include both observable and unobservable inputs. These valuations may include an estimated basis adjustment from an illiquid trading point to a liquid trading point for which active price quotations are available. Such instruments are categorized in Level 3. For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations whose contract tenure extends into unobservable periods. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility, and contract duration. Such instruments are categorized in Level 3 as the model inputs generally are not observable. Forward 143 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 18 — Fair Value of Financial Assets and Liabilities price curves for the power market utilized by the front office to manage the portfolio, are reviewed and verified by the middle office, and used for financial reporting by the back office. We consider credit and nonperformance risk in the valuation of derivative contracts categorized in Level 2 and 3, including both historical and current market data, in our assessment of credit and nonperformance risk by counterparty. Due to master netting agreements and collateral posting requirements, the impacts of credit and nonperformance risk were not material to the financial statements. Disclosed below is detail surrounding our significant Level 3 valuations. The calculated fair value includes marketability discounts for margining provisions and other attributes. The Level 3 balance generally consists of forward sales and purchases of power and natural gas and certain transmission congestion contracts. We utilize various inputs and factors including market data and assumptions that market participants would use in pricing assets or liabilities as well as assumptions about the risks inherent in the inputs to the valuation technique. The inputs and factors include forward commodity prices, commodity price volatility, contractual volumes, delivery location, interest rates, credit quality of counterparties, and credit enhancements. For commodity derivatives, the primary input to the valuation models is the forward commodity price curve for each instrument. Forward commodity price curves are derived by risk management for liquid locations and by the traders and portfolio managers for illiquid locations. All locations are reviewed and verified by risk management considering published exchange transaction prices, executed bilateral transactions, broker quotes, and other observable or public data sources. The relevant forward commodity curve used to value each of the derivatives depends on a number of factors, including commodity type, delivery location, and delivery period. Price volatility varies by commodity and location. When appropriate, we discount future cash flows using risk free interest rates with adjustments to reflect the credit quality of each counterparty for assets and our own credit quality for liabilities. The level of observability of a forward commodity price varies generally due to the delivery location and delivery period. Certain delivery locations including PJM West Hub (for power) and Henry Hub (for natural gas) are more liquid and prices are observable for up to three years in the future. The observability period of volatility is generally shorter than the underlying power curve used in option valuations. The forward curve for a less liquid location is estimated by using the forward curve from the liquid location and applying a spread to represent the cost to transport the commodity to the delivery location. This spread does not typically represent a majority of the instrument’s market price. As a result, the change in fair value is closely tied to liquid market movements and not a change in the applied spread. The change in fair value associated with a change in the spread is generally immaterial. An average spread calculated across all Level 3 power and gas delivery locations is approximately $ 3.33 and $ 0.53 for power and natural gas, respectively. Many of the commodity derivatives are short term in nature and thus a majority of the fair value may be based on observable inputs even though the contract as a whole must be classified as Level 3. See Note 16 — Derivative Financial Instruments for additional information on mark-to-market derivatives. The following table presents the significant inputs to the forward curve used to value these positions: Type of trade Fair Value as of December 31, 2021 Fair Value as of December 31, 2020 Valuation Technique Unobservable Input 2021 Range & Arithmetic Average 2020 Range & Arithmetic Average Mark-to-market derivatives—Economic hedges (a)(b) $ ( 66 ) $ 245 Discounted Cash Flow Forward power price $ 8.86 - $ 481 $ 55 $ 2.25 - $ 163 $ 30 Forward gas price $ 1.69 - $ 17 $ 3.50 $ 1.57 - $ 7.88 $ 2.59 Option Model Volatility percentage 24 % - 284 % 56 % 11 % - 237 % 32 % __________ (a) The valuation techniques, unobservable inputs, ranges, and arithmetic averages are the same for the asset and liability positions. (b) The fair values do not include cash collateral (received) posted on level three positions of $( 34 ) million and $ 162 million as of December 31, 2021 and December 31, 2020, respectively. The inputs listed above, which are as of the balance sheet date, would have a direct impact on the fair values of the above instruments if they were adjusted. The significant unobservable inputs used in the fair value measurement of our commodity derivatives are forward commodity prices and for options is price volatility. 144 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 18 — Fair Value of Financial Assets and Liabilities Increases (decreases) in the forward commodity price in isolation would result in significantly higher (lower) fair values for long positions (contracts that give us the obligation or option to purchase a commodity), with offsetting impacts to short positions (contracts that give us the obligation or right to sell a commodity). Increases (decreases) in volatility would increase (decrease) the value for the holder of the option (writer of the option). Generally, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of volatility of prices. An increase to the reserves listed above would decrease the fair value of the positions. An increase to the heat rate or renewable factors would increase the fair value accordingly. Generally, interrelationships exist between market prices of natural gas and power. As such, an increase in natural gas pricing would potentially have a similar impact on forward power markets. 19. Commitments and Contingencies Commercial Commitments. Commercial commitments as of December 31, 2021, representing commitments potentially triggered by future events, were as follows: Expiration within Total 2022 2023 2024 2025 2026 2027 and beyond Letters of credit $ 2,380 $ 2,279 $ 101 $ — $ — $ — $ — Surety bonds (a) 899 882 17 — — — — Total commercial commitments $ 3,279 $ 3,161 $ 118 $ — $ — $ — $ — __________ (a) Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds. Nuclear Insurance We are subject to liability, property damage and other risks associated with major incidents at any of our nuclear stations. We have mitigated our financial exposure to these risks through insurance and other industry risk-sharing provisions. The Price-Anderson Act was enacted to ensure the availability of funds for public liability claims arising from an incident at any of the U.S. licensed nuclear facilities and to limit the liability of nuclear reactor owners for such claims from any single incident. As of December 31, 2021, the current liability limit per incident is $ 13.5 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors at least once every five years with the last adjustment effective November 1, 2018. In accordance with the Price-Anderson Act, we maintain financial protection at levels equal to the amount of liability insurance available from private sources through the purchase of private nuclear energy liability insurance for public liability claims that could arise in the event of an incident. Effective January 1, 2017, the required amount of nuclear energy liability insurance purchased is $ 450 million for each operating site. Claims exceeding that amount are covered through mandatory participation in a financial protection pool, as required by the Price Anderson-Act, which provides the additional $ 13.1 billion per incident in funds available for public liability claims. Participation in this secondary financial protection pool requires the operator of each reactor to fund its proportionate share of costs for any single incident that exceeds the primary layer of financial protection. Our share of this secondary layer would be approximately $ 2.8 billion, however any amounts payable under this secondary layer would be capped at $ 413 million per year. In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay public liability claims exceeding the $ 13.5 billion limit for a single incident. As part of the execution of the NOSA on April 1, 2014, we executed an Indemnity Agreement pursuant to which we agreed to indemnify EDF and its affiliates against third-party claims that may arise from any future nuclear incident (as defined in the Price-Anderson Act) in connection with the CENG nuclear plants or their operations. See Note 21 — Variable Interest Entities for additional information on our operations relating to CENG. We are required each year to report to the NRC the current levels and sources of property insurance that demonstrates we possess sufficient financial resources to stabilize and decontaminate a reactor and reactor station site in the event of an accident. The property insurance maintained for each facility is currently provided 145 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 19 — Commitments and Contingencies through insurance policies purchased from NEIL, an industry mutual insurance company of which we are a member. NEIL may declare distributions to its members as a result of favorable operating experience. In recent years, NEIL has made distributions to its members. Our portion of the annual distribution declared by NEIL is estimated to be $ 113 million for 2021, and was $ 75 million and $ 136 million for 2020 and 2019, respectively. The distributions were recorded as a reduction to Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. Premiums paid to NEIL by its members are also subject to a potential assessment for adverse loss experience in the form of a retrospective premium obligation. NEIL has never assessed this retrospective premium since its formation in 1973, and we cannot predict the level of future assessments, if any. The current maximum aggregate annual retrospective premium obligation for us is approximately $ 229 million. NEIL requires its members to maintain an investment grade credit rating or to ensure collectability of their annual retrospective premium obligation by providing a financial guarantee, letter of credit, deposit premium, or some other means of assurance. NEIL provides “all risk” property damage, decontamination and premature decommissioning insurance for each station for losses resulting from damage to its nuclear plants, either due to accidents or acts of terrorism. If the decision is made to decommission the facility, a portion of the insurance proceeds will be allocated to a fund, which we are required by the NRC to maintain, to provide for decommissioning the facility. In the event of an insured loss, we are unable to predict the timing of the availability of insurance proceeds to us and the amount of such proceeds that would be available. In the event that one or more acts of terrorism cause accidental property damage within a twelve-month period from the first accidental property damage under one or more policies for all insured plants, the maximum recovery by us will be an aggregate of $ 3.2 billion plus such additional amounts as the insurer may recover for all such losses from reinsurance, indemnity and any other source, applicable to such losses. For our insured losses, we are self-insured to the extent that losses are within the policy deductible or exceed the amount of insurance maintained. Uninsured losses and other expenses, to the extent not recoverable from insurers or the nuclear industry, could also be borne by us. Any such losses could have a material adverse effect on our financial statements. Spent Nuclear Fuel Obligation Under the NWPA, the DOE is responsible for the development of a geologic repository for and the disposal of SNF and high-level radioactive waste. As required by the NWPA, we are a party to contracts with the DOE (Standard Contracts) to provide for disposal of SNF from our nuclear generating stations. In accordance with the NWPA and the Standard Contracts, we had previously paid the DOE one mill ($ 0.001 ) per kWh of net nuclear generation for the cost of SNF disposal. Due to the lack of a viable disposal program, the DOE reduced the SNF disposal fee to zero in May 2014. Until a new fee structure is in effect, we will not accrue any further costs related to SNF disposal fees. This fee may be adjusted prospectively to ensure full cost recovery. We currently assume the DOE will begin accepting SNF in 2035 and use that date for purposes of estimating the nuclear decommissioning AROs. The SNF acceptance date assumption is based on management’s estimate of the amount of time required for DOE to select a site location and develop the necessary infrastructure for long-term SNF storage. The NWPA and the Standard Contracts required the DOE to begin taking possession of SNF generated by nuclear generating units no later than January 31, 1998. The DOE, however, failed to meet that deadline and its performance has been, and is expected to remain, delayed significantly. In August 2004, we and the DOJ, in close consultation with the DOE, reached a settlement under which the government agreed to reimburse us, subject to certain damage limitations based on the extent of the government’s breach, for costs associated with storage of SNF at our nuclear stations pending the DOE’s fulfillment of its obligations. Calvert Cliffs, Ginna and Nine Mile Point each have separate settlement agreements in place with the DOE which were extended during 2020 to provide for the reimbursement of SNF storage costs through December 31, 2022. FitzPatrick also has a separate settlement agreement in place with the DOE that was established in 2021 to provide for reimbursement of SNF storage costs through December 31, 2022. We submit annual reimbursement requests to the DOE for 146 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 19 — Commitments and Contingencies costs associated with the storage of SNF. In all cases, reimbursement requests are made only after costs are incurred and only for costs resulting from DOE delays in accepting the SNF. Under the settlement agreements, we received total cumulative cash reimbursements of $ 1,492 million through December 31, 2021 for costs incurred. After considering the amounts due to co-owners of certain nuclear stations and to the former owner of Oyster Creek, we received net cumulative cash reimbursements of $ 1,294 million. As of December 31, 2021 and 2020, the amount of SNF storage costs for which reimbursement has been or will be requested from the DOE under the DOE settlement agreements is as follows: December 31, 2021 December 31, 2020 DOE receivable - current (a) $ 241 $ 129 DOE receivable - noncurrent (b) 85 70 Amounts owed to co-owners (c) ( 35 ) ( 23 ) __________ (a) Recorded in Other accounts receivable. (b) Recorded in Deferred debits and other assets, other. (c) Recorde d in Other accounts receivable. Represents amounts owed to the co-owners of Peach Bottom, Quad Cities, and Nine Mile Point Unit 2 generating facilitie s . The Standard Contracts with the DOE also required the payment to the DOE of a one-time fee applicable to nuclear generation through April 6, 1983. The below table outlines the SNF liability recorded as of December 31, 2021 and 2020: December 31, 2021 December 31, 2020 Former ComEd units (a) $ 1,083 $ 1,082 Fitzpatrick (b) 127 126 Total SNF Obligation $ 1,210 $ 1,208 __________ (a) ComEd previously elected to defer payment of the one-time fee of $ 277 million for its units, with interest to the date of payment, until just prior to the first delivery of SNF to the DOE. The unfunded liabilities for SNF disposal costs, including the one-time fee, were transferred to us as part of Exelon’s 2001 corporate restructuring. (b) A prior owner of FitzPatrick elected to defer payment of the one-time fee of $ 34 million, with interest to the date of payment, for the FitzPatrick unit. As part of the FitzPatrick acquisition on March 31, 2017, we assumed a SNF liability for the DOE one-time fee obligation with interest related to FitzPatrick along with an offsetting asset, included in Other deferred debits and other assets, for the contractual right to reimbursement from NYPA, a prior owner of FitzPatrick, for amounts paid for the FitzPatrick DOE one-time fee obligation. Interest for our SNF liabilities accrues at the 13-week Treasury Rate. The 13-week Treasury Rate in effect for calculation of the interest accrual at December 31, 2021 was 0.051 % for the deferred amount transferred from ComEd and 0.041 % for the deferred FitzPatrick amount. The following table summarizes sites for which we do not have an outstanding SNF Obligation: Description Sites Fees have been paid Former PECO units, Clinton and Calvert Cliffs Outstanding SNF Obligation remains with former owners Nine Mile Point, Ginna and TMI Environmental Remediation Matters General. Our operations have in the past, and may in the future, require substantial expenditures to comply with environmental laws. Additionally, under Federal and state environmental laws, we are generally liable for the costs of remediating environmental contamination of property now or formerly owned by us and of property contaminated by hazardous substances generated by us. We own or lease a number of real estate parcels, including parcels on which our operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. In addition, we are currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future. Unless otherwise disclosed, we cannot reasonably estimate whether we will incur significant liabilities for additional investigation and remediation costs at these or additional sites 147 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 19 — Commitments and Contingencies identified by us, environmental agencies or others. Additional costs could have a material, unfavorable impact on our financial statements. As of December 31, 2021 and 2020, we had accrued undiscounted amounts of $ 120 million and $ 121 million, respectively, for environmental liabilities in Other current liabilities and Other deferred credits and other liabilities in the Consolidated Balance Sheets. Cotter Corporation. The EPA has advised Cotter Corporation (Cotter), a former ComEd subsidiary, that it is potentially liable in connection with radiological contamination at a site known as the West Lake Landfill in Missouri. In 2000, ComEd sold Cotter to an unaffiliated third-party. As part of the sale, ComEd agreed to indemnify Cotter for any liability arising in connection with the West Lake Landfill. In connection with Exelon’s 2001 corporate restructuring, this responsibility to indemnify Cotter was transferred to us. Including Cotter, there are three PRPs participating in the West Lake Landfill remediation proceeding. Our investigation has identified a number of other parties who also may be PRPs and could be liable to contribute to the final remedy. Further investigation is ongoing. In September 2018, the EPA issued its Record of Decision Amendment (RODA) for the selection of a final remedy. The RODA modified the remedy previously selected by EPA in its 2008 Record of Decision (ROD). While the ROD required only that the radiological materials and other wastes at the site be capped, the 2018 RODA requires partial excavation of the radiological materials in addition to the previously selected capping remedy. The RODA also allows for variation in depths of excavation depending on radiological concentrations. The EPA and the PRPs have entered into a Consent Agreement to perform the Remedial Design, which is expected to be completed in late 2024. In March 2019, the PRPs received Special Notice Letters from the EPA to perform the Remedial Action work. On October 8, 2019, Cotter (our indemnitee) provided a non-binding good faith offer to conduct, or finance, a portion of the remedy, subject to certain conditions. The total estimated cost of the remedy, taking into account the current EPA technical requirements and the total costs expected to be incurred collectively by the PRPs in fully executing the remedy, is approximately $ 290 million, including cost escalation on an undiscounted basis, which would be allocated among the final group of PRPs. We have determined that a loss associated with the EPA’s partial excavation and enhanced landfill cover remedy is probable and have recorded a liability, included in the total amount as discussed above, that reflects management’s best estimate of Cotter’s allocable share of the ultimate cost. Given the joint and several nature of this liability, the magnitude of our ultimate liability will depend on the actual costs incurred to implement the required remedy as well as on the nature and terms of any cost-sharing arrangements with the final group of PRPs. Therefore, it is reasonably possible that the ultimate cost and Cotter's associated allocable share could differ significantly once these uncertainties are resolved, which could have a material impact on our financial statements. One of the other PRPs has indicated it will be making a contribution claim against Cotter for costs that it has incurred to prevent a subsurface fire from spreading to those areas of the West Lake Landfill where radiological materials are believed to have been disposed. At this time, we do not possess sufficient information to assess this claim and therefore are unable to estimate a range of loss, if any. As such, no liability has been recorded for the potential contribution claim. It is reasonably possible, however, that resolution of this matter could have a material, unfavorable impact on our financial statements. In January 2018, the PRPs were advised by the EPA that it will begin an additional investigation and evaluation of groundwater conditions at the West Lake Landfill. In September 2018, the PRPs agreed to an Administrative Settlement Agreement and Order on Consent for the performance by the PRPs of the groundwater Remedial Investigation Feasibility Study (RI/FS). The purpose of this RI/FS is to define the nature and extent of any groundwater contamination from the West Lake Landfill site and evaluate remedial alternatives. We estimate the undiscounted cost for the groundwater RI/FS to be approximately $ 40 million. We determined a loss associated with the RI/FS is probable and have recorded a liability, included in the total amount as discussed above, that reflects management’s best estimate of Cotter’s allocable share of the cost among the PRPs. At this time we cannot predict the likelihood, or the extent to which, if any, remediation activities may be required and therefore cannot estimate a reasonably possible range of loss for response costs beyond those associated with the RI/FS component. It is reasonably possible, however, that resolution of this matter could have a material, unfavorable impact on our financial statements. In August 2011, Cotter was notified by the DOJ that Cotter is considered a PRP with respect to the government’s clean-up costs for contamination attributable to low level radioactive residues at a former storage and reprocessing facility named Latty Avenue near St. Louis, Missouri. The Latty Avenue site is included in ComEd’s 148 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 19 — Commitments and Contingencies (now our) indemnification responsibilities discussed above as part of the sale of Cotter. The radioactive residues had been generated initially in connection with the processing of uranium ores as part of the U.S. Government’s Manhattan Project. Cotter purchased the residues in 1969 for initial processing at the Latty Avenue facility for the subsequent extraction of uranium and metals. In 1976, the NRC found that the Latty Avenue site had radiation levels exceeding NRC criteria for decontamination of land areas. Latty Avenue was investigated and remediated by the United States Army Corps of Engineers pursuant to funding under FUSRAP (Formerly Utilized Sites Remedial Action Program). Pursuant to a series of annual agreements since 2011, the DOJ and the PRPs have tolled the statute of limitations until February 28, 2022 so that settlement discussions can proceed. On August 3, 2020, the DOJ advised Cotter and the other PRPs that it is seeking approximately $ 90 million from all the PRPs and has directed that the PRPs must submit a good faith joint proposed settlement offer. In December 2021, a good faith offer was submitted to the government and negotiations are expected to commence in the first quarter of 2022. We have determined that a loss associated with this matter is probable under our indemnification agreement with Cotter and have recorded an estimated liability, included in the total amount as discussed above. Benning Road Site . In September 2010, PHI received a letter from EPA identifying the Benning Road site as one of six land-based sites potentially contributing to contamination of the lower Anacostia River. A portion of the site was formerly the location of a Pepco Energy Services electric generating facility, which was deactivated in June 2012. The remaining portion of the site consists of a Pepco transmission and distribution service center that remains in operation. In December 2011, the U.S. District Court for the District of Columbia approved a Consent Decree entered into by Pepco and Pepco Energy Services with the DOEE, which requires Pepco and Pepco Energy Services to conduct a RI/FS for the Benning Road site and an approximately 10 to 15-acre portion of the adjacent Anacostia River. Since 2013, Pepco and Pepco Energy Services (now us, pursuant to Exelon's 2016 acquisition of PHI) have been performing RI work and have submitted multiple draft RI reports to the DOEE. In September 2019, we and Pepco issued a draft “final” RI report which DOEE approved on February 3, 2020. We and Pepco are developing a FS to evaluate possible remedial alternatives for submission to DOEE. The Court has established a schedule for completion of the FS, and approval by the DOEE, by September 16, 2022. After completion and approval of the FS, DOEE will prepare a Proposed Plan for public comment and then issue a ROD identifying any further response actions determined to be necessary. We have determined that a loss associated with this matter is probable and have accrued an estimated liability, included in the total amount as discussed above. Pursuant to the terms of the Separation agreement, all future liabilities associated with this matter were transferred to Exelon on February 1, 2022, except for the continuing obligation to fund 5% for the completion of the remedial investigation and feasibility study and any other requirements of the 2011 Consent Decree. Litigation and Regulatory Matters Asbestos Personal Injury Claims. We maintain a reserve for claims associated with asbestos-related personal injury actions at certain facilities that are currently owned by us or were previously owned by ComEd and PECO. The estimated liabilities are recorded on an undiscounted basis and exclude the estimated legal costs associated with handling these matters, which could be material. At December 31, 2021 and 2020, we recorded estimated liabilities of approximately $ 81 million and $ 89 million, respectively, in total for asbestos-related bodily injury claims. As of December 31, 2021, approximately $ 17 million of this amount related to 211 open claims presented to us, while the remaining $ 64 million is for estimated future asbestos-related bodily injury claims anticipated to arise through 2055, based on actuarial assumptions and analyses, which are updated on an annual basis. On a quarterly basis, we monitor actual experience against the number of forecasted claims to be received and expected claim payments and evaluate whether adjustments to the estimated liabilities are necessary. Impacts of the February 2021 Extreme Cold Weather Event and Texas-based Generating Assets Outages. Beginning on February 15, 2021, our Texas-based generating assets within the ERCOT market, specifically Colorado Bend II, Wolf Hollow II, and Handley, experienced outages as a result of extreme cold weather conditions. In addition, those weather conditions drove increased demand for service, dramatically increased wholesale power prices, and also increased gas prices in certain regions. See Note 3 — Regulatory Matters for additional information. Various lawsuits have been filed against us since March 2021 related to these events, including: 149 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 19 — Commitments and Contingencies • On March 5, 2021, we, along with more than 160 power generators and transmission and distribution companies, were sued by approximately 160 individually named plaintiffs, purportedly on behalf of all Texans who allegedly suffered loss of life or sustained personal injury, property damage or other losses as a result of the weather events. The plaintiffs allege that the defendants failed to properly prepare for the cold weather and failed to properly conduct their operations, seeking compensatory as well as punitive damages. On April 26, 2021, another multi-plaintiff lawsuit was filed on behalf of approximately 90 plaintiffs against more than 300 defendants, including us, involving similar allegations of liability and claims of personal injury and property damage. Since March 2021, approximately 60 additional lawsuits, naming multiple defendants including us, were filed by individual or multiple plaintiffs in different Texas counties, all arising out of the February weather events. These additional lawsuits allege wrongful death, property damage, or other losses. Co-defendants in these lawsuits include ERCOT, transmission and distribution utilities and other generators. On December 28, 2021, approximately 130 insurance companies which insured Texas homeowners and businesses filed a subrogation lawsuit against multiple defendants alleging that defendants were at fault for the energy failure that resulted from the winter storm, causing significant property damage to the insureds. Additionally, as of January 28, 2022, we have been added to approximately 80 additional wrongful death, personal injury, and property damage lawsuits through the Multi-District-Litigation (MDL) pending in Texas state court. The MDL now includes all of the above-described Texas state court matters. We dispute liability and deny that we are responsible for any of plaintiffs’ alleged claims and are vigorously contesting them. No loss contingencies have been reflected in the consolidated financial statements with respect to these matters, as such contingencies are neither probable nor reasonably estimable at this time. • On March 22, 2021, an LDC filed a lawsuit in Missouri federal court against us for breach of contract and unjust enrichment, seeking damages of approximately $ 40 million. The plaintiff claims that we failed to deliver gas to our customers in February of 2021, causing the plaintiff to incur damages by forcing it to purchase gas for our customers and by our refusal to pay the resulting penalties. On March 26, 2021, we filed a complaint with the MPSC against the LDC to void the OFO penalties, or alternatively to grant a waiver or variance from the tariff requirements, to prohibit the LDC from billing or otherwise attempting to collect from us or any Missouri customer any portion of the penalties claimed by the LDC until the resolution of the complaint, and to prohibit the LDC from taking any retaliatory measure, including termination of service. On September 1, 2021, the MPSC consolidated our complaint with two other similar complaints from other companies. On January 4, 2022, the court denied our motion to dismiss, but in the alternative granted its motion to stay pending MPSC resolution of our complaint. The MPSC has scheduled an evidentiary hearing for the three consolidated complaint cases in April 2022. Based on the penalty provisions within the tariff that was in effect at the relevant time, we have recorded a liability of approximately $ 40 million as of December 31, 2021. General. We are involved in various other litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. We maintain accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of reasonably possible loss, particularly where (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss. 20. Stock-Based Compensation Plans Our employees were granted stock-based awards through the Exelon LTIP as of December 31, 2021, which primarily includes performance share awards, restricted stock units, and stock options. We also grant cash awards. Performance share awards are typically settled 50 % in common stock and 50 % in cash at the end of a three-year performance period, subject to certain ownership thresholds that, if met, may result in cash settlement of the entire award. The following table does not include expense related to cash awards granted as they are not considered stock-based compensation plans under the applicable authoritative guidance. The following table presents the stock-based compensation expense included in the Consolidated Statements of Operations and Comprehensive Income: 150 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 20 — Stock-Based Compensation Plans Year Ended December 31, 2021 2020 2019 Total stock-based compensation expense included in operating and maintenance expense $ 47 $ 27 $ 37 Income tax benefit ( 12 ) ( 7 ) ( 10 ) Total after-tax stock-based compensation expense $ 35 $ 20 $ 27 Impact of Separation from Exelon Effective February 1, 2022, we established our own LTIP and began granting cash and stock-based awards that primarily include performance share awards and restricted stock units. The existing, unvested cash and stock-based awards issued through the Exelon LTIP were modified in connection with the separation to align with our performance metrics and maintain an equivalent value immediately before and after separation. 21. Variable Interest Entities At December 31, 2021 and 2020, we consolidated several VIEs or VIE groups for which we are the primary beneficiary (see Consolidated VIEs below) and had significant interests in several other VIEs for which we do not have the power to direct the entities’ activities and, accordingly, we were not the primary beneficiary (see Unconsolidated VIEs below). Consolidated and unconsolidated VIEs are aggregated to the extent that the entities have similar risk profiles. Consolidated VIEs The table below shows the carrying amounts and classification of the consolidated VIEs’ assets and liabilities included in the consolidated financial statements as of December 31, 2021 and 2020. The assets, except as noted in the footnotes to the table below, can only be used to settle obligations of the VIEs. The liabilities, except as noted in the footnotes to the table below, are such that creditors, or beneficiaries, do not have recourse to our general credit. 151 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 21 — Variable Interest Entities December 31, 2021 December 31, 2020 Cash and cash equivalents $ 35 $ 98 Restricted cash and cash equivalents 48 44 Accounts receivable Customer 24 148 Other 6 36 Inventories, net Materials and supplies 14 244 Assets held for sale (a) — 101 Other current assets 405 691 Total current assets 532 1,362 Property, plant and equipment, net 2,027 5,803 Nuclear decommissioning trust funds — 3,007 Other noncurrent assets 215 291 Total noncurrent assets 2,242 9,101 Total assets (b) $ 2,774 $ 10,463 Long-term debt due within one year $ 70 $ 68 Accounts payable 10 81 Accrued expenses 21 70 Liabilities held for sale (a) — 16 Other current liabilities 1 9 Total current liabilities 102 244 Long-term debt 822 889 Asset retirement obligations 151 2,318 Other noncurrent liabilities 3 129 Total noncurrent liabilities 976 3,336 Total liabilities (c) $ 1,078 $ 3,580 _______ (a) We entered into an agreement for the sale of a significant portion of our solar business. As a result of this transaction, in the fourth quarter of 2020, we reclassified the consolidated VIEs' solar assets and liabilities as held for sale. Refer to Note 2 — Mergers, Acquisitions, and Dispositions for additional information on the sale of the solar business. (b) Our balances include unrestricted assets f or current unamortized energy contract assets of $ 23 million and $ 22 million, disclosed within other current assets in the table above, noncurrent unamortized energy contract assets of $ 202 million and $ 249 million, disclosed within other noncurrent assets in the table above, Assets held for sale of $ 0 million and $ 9 million, and other unrestricted assets of $ 0 million and $ 1 million, as of December 31, 2021 and 2020, respectively. (c) Our balances include liabilities with recourse of $ 1 million and $ 8 million as of December 31, 2021 and 2020, respectively. 152 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 21 — Variable Interest Entities As of December 31, 2021 and 2020, our consolidated VIEs included the following: Consolidated VIE or VIE groups: Reason entity is a VIE: Reason we are the primary beneficiary: CENG - A joint venture between us and EDF. We had a 50.01 % equity ownership in CENG as of December 31, 2020 and acquired EDF's 49.99 % equity interest on August 6, 2021 resulting in CENG no longer being classified as a consolidated VIE beginning in the third quarter of 2021. See additional discussion below. Disproportionate relationship between equity interest and operational control as a result of the NOSA described further below. We conduct the operational activities. CRP - A collection of wind and solar project entities. We have a 51 % equity ownership in CRP. See additional discussion below. Similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner. We conduct the operational activities. Bluestem Wind Energy Holdings, LLC - A Tax Equity structure which is consolidated by CRP. We have a noncontrolling interest. Similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner. We conduct the operational activities. Antelope Valley - A solar generating facility, which is 100 % owned by us. Antelope Valley sells all of its output to PG&E through a PPA. The PPA contract absorbs variability through a performance guarantee. We conduct all activities. Equity investment in distributed energy company - We have a 31 % equity ownership. This distributed energy company has an interest in an unconsolidated VIE. (See Unconsolidated VIEs disclosure below). We fully impaired this investment in the third quarter of 2019. Refer to Note 12 — Asset Impairments for additional information. Similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner. We conduct the operational activities. NER - A bankruptcy remote, special purpose entity which is 100 % owned by us, which purchases certain of our customer accounts receivable arising from the sale of retail electricity. NER’s assets will be available first and foremost to satisfy the claims of the creditors of NER. Refer to Note 6 —Accounts Receivable for additional information on the sale of receivables. Equity capitalization is insufficient to support its operations. We conduct all activities. CENG - On April 1, 2014, we, CENG, and subsidiaries of CENG executed the NOSA pursuant to which we conduct all activities associated with the operations of the CENG fleet and provide corporate and administrative services to CENG and the CENG fleet for the remaining life of the CENG nuclear plants as if they were a part of our nuclear fleet, subject to the CENG member rights of EDF. 153 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 21 — Variable Interest Entities On November 20, 2019, we received notice of EDF's intention to exercise the put option to sell us its equity interest in CENG and the put automatically exercised on January 19, 2020. On August 6, 2021, we entered into a settlement agreement with EDF pursuant to which we purchased EDF's equity interest in CENG and resulted in CENG no longer being classified as a consolidated VIE beginning in the third quarter of 2021. Refer to Note 2 — Mergers, Acquisitions, and Dispositions for additional information. We provide the following support to CENG: • We executed an Indemnity Agreement pursuant to which we agreed to indemnify EDF against third-party claims that may arise from any future nuclear incident (as defined in the Price-Anderson Act) in connection with the CENG nuclear plants or their operations. Exelon guarantees our obligations under this Indemnity Agreement and will continue to do so post-separation, however, any calls on this guarantee would require us to reimburse Exelon under the terms of the Separation Agreement. See Note 19 — Commitments and Contingencies and Note 24 — Separation from Exelon for more details. • Exelon has executed an agreement to provide up to $ 245 million to support the operations of CENG as well as a $ 165 million guarantee of CENG’s cash pooling agreement with its subsidiaries. Both the support agreement and guarantee terminated upon separation and we executed new support agreements for the benefit of each CENG subsidiary plant owner. Prior to August 6, 2021, we and EDF shared in the $ 688 million of contingent payment obligations for the payment of contingent retrospective premium adjustments for the nuclear liability insurance. Following the execution of the settlement agreement, EDF no longer shares in the obligation. CRP - CRP is a collection of wind and solar project entities and some of these project entities are VIEs that are consolidated by CRP. While we or CRP own 100 % of the solar entities and 100 % of the majority of the wind entities, it has been determined that the wholly owned solar and wind entities are VIEs because the entities' customers absorb price variability from the entities through fixed price power and/or REC purchase agreements. Additionally, for the wind entities that have minority interests, it has been determined that these entities are VIEs because the governance rights of some investors are not proportional to their financial rights. We are the primary beneficiary of these solar and wind entities that qualify as VIEs because we control operations and direct all activities of the facilities. There is limited recourse to us related to certain solar and wind entities. In 2017, our interests in CRP were contributed to and are pledged for the CR non-recourse debt project financing structure. Refer to Note 17 — Debt and Credit Agreements for additional information. Unconsolidated VIEs Our variable interests in unconsolidated VIEs generally include equity investments and energy purchase and sale contracts. For the equity investments, the carrying amount of the investments is reflected in the Consolidated Balance Sheets in Investments. For the energy purchase and sale contracts (commercial agreements), the carrying amount of assets and liabilities in the Consolidated Balance Sheets that relate to our involvement with the VIEs are predominantly related to working capital accounts and generally represent the amounts owed by, or owed to, us for the deliveries associated with the current billing cycles under the commercial agreements. As of December 31, 2021 and 2020, we had significant unconsolidated variable interests in several VIEs for which we were not the primary beneficiary. These interests include certain equity method investments and certain commercial agreements. 154 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 21 — Variable Interest Entities The following table presents summary information about our significant unconsolidated VIE entities: December 31, 2021 December 31, 2020 Commercial Agreement VIEs Equity Investment VIEs Total Commercial Agreement VIEs Equity Investment VIEs Total Total assets (a) $ 772 $ 372 $ 1,144 $ 777 $ 401 $ 1,178 Total liabilities (a) 80 216 296 61 223 284 Our ownership interest in VIE (a) — 139 139 — 157 157 Other ownership interests in VIE (a) 692 17 709 716 21 737 __________ (a) These items represent amounts on the unconsolidated VIE balance sheets, not in the Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs. We do not have any exposure to loss as we do not have a carrying amount in the equity investment VIEs as o f December 31, 2021 and 2020. As of December 31, 2021 and 2020, the unconsolidated VIEs consist of: Unconsolidated VIE groups: Reason entity is a VIE: Reason we are not the primary beneficiary: Equity investments in distributed energy companies - 1) We have a 90 % equity ownership in a distributed energy company. 2) We, via a consolidated VIE, have a 90 % equity ownership in another distributed energy company (See Consolidated VIEs disclosure above). We fully impaired this investment in the third quarter of 2019. Refer to Note 12 — Asset Impairments for additional information. Similar structures to a limited partnership and the limited partners do not have kick out rights with respect to the general partner. We do not conduct the operational activities. Energy Purchase and Sale agreements - We have several energy purchase and sale agreements with generating facilities. PPA contracts that absorb variability through fixed pricing. We do not conduct the operational activities. 22. Supplemental Financial Information Supplemental Statement of Operations Information The following tables provide additional information about material items recorded in the Consolidated Statements of Operations and Comprehensive Income. Taxes other than income taxes For the Years Ended December 31, 2021 2020 2019 Gross receipts (a) $ 99 $ 99 $ 112 Property 268 265 274 Payroll 109 113 115 __________ (a) Represent gross receipts taxes related to our retail operations. The offsetting collection of gross receipts taxes from customers is recorded in revenues in the Consolidated Statements of Operations and Comprehensive Income. 155 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 22 — Supplemental Financial Information Other, net For the Years Ended December 31, 2021 2020 2019 Decommissioning-related activities: Net realized income on NDT funds (a) Regulatory Agreement Units $ 817 $ 185 $ 297 Non-Regulatory Agreement Units 449 160 363 Net unrealized gains on NDT funds Regulatory Agreement Units 351 724 795 Non-Regulatory Agreement Units 209 391 411 Regulatory offset to NDT fund-related activities (b) ( 917 ) ( 729 ) ( 876 ) Decommissioning-related activities 909 731 990 Net unrealized (losses) gains from equity investments (c) ( 160 ) 186 — __________ (a) Realized income includes interest, dividends and realized gains and losses on sales of NDT fund investments. (b) Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units except for decommissioning-related impacts that were not offset for the Byron units starting in the second quarter of 2021, including the elimination of income taxes related to all NDT fund activity for those units. With our September 15, 2021 reversal of the previous decision to retire Byron, we resumed contractual offset for Byron as of that date. See Note 10 — Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning and the contractual offset suspension for the Byron units. (c) Net unrealized (losses) gains from equity investments that became publicly traded in the fourth quarter of 2020 and the first half of 2021. Supplemental Cash Flow Information The following tables provide additional information about material items recorded in the Consolidated Statements of Cash Flows. Depreciation, amortization and accretion For the Years Ended December 31, 2021 2020 2019 Property, plant, and equipment (a) $ 2,954 $ 2,070 $ 1,485 Amortization of intangible assets, net (a) 49 53 50 Amortization of energy contract assets and liabilities (b) 31 30 21 Nuclear fuel (c) 992 983 1,016 ARO accretion (d) 514 500 491 Total depreciation, amortization, and accretion $ 4,540 $ 3,636 $ 3,063 _________ (a) Included in Depreciation and amortization in the Consolidated Statements of Operations and Comprehensive Income. (b) Included in Operating revenues or Purchased power and fuel expense in the Consolidated Statements of Operations and Comprehensive Income. (c) Included in Purchased power and fuel expense in the Consolidated Statements of Operations and Comprehensive Income. (d) Included in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. 156 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 22 — Supplemental Financial Information Cash paid (refunded) during the year: For the Years Ended December 31, 2021 2020 2019 Interest (net of amount capitalized) $ 275 $ 331 $ 373 Income taxes (net of refunds) 426 70 ( 44 ) Other non-cash operating activities: For the Years Ended December 31, 2021 2020 2019 Pension and non-pension postretirement benefit costs $ 123 $ 115 $ 135 Allowance for credit losses 32 17 31 Other decommissioning-related activity (a) ( 946 ) ( 659 ) ( 506 ) Energy-related options (b) 125 104 22 Severance costs ( 73 ) 90 — Provision for excess and obsolete inventory ( 13 ) 128 — Amortization of operating ROU asset 119 155 172 __________ (a) Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units except for decommissioning-related impacts that were not offset for the Byron units starting in the second quarter of 2021, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income, and income taxes related to all NDT fund activity for these units. With our September 15, 2021 reversal of the previous decision to retire Byron, we resumed contractual offset for Byron as of that date. See Note 10 — Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning and for additional information on the contractual offset suspension for the Byron units. (b) Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations. The following table provides a reconciliation of cash, restricted cash, and cash equivalents reported in the Consolidated Balance Sheets that sum to the total of the same amounts in the Consolidated Statements of Cash Flows. December 31, 2021 December 31, 2020 December 31, 2019 December 31, 2018 Cash and cash equivalents $ 504 $ 226 $ 303 $ 750 Restricted cash and cash equivalents 72 89 146 153 Cash, restricted cash, and cash equivalents - Held for Sale — 12 — — Total cash, restricted cash, and cash equivalents $ 576 $ 327 $ 449 $ 903 157 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 22 — Supplemental Financial Information Supplemental Balance Sheet Information The following tables provide additional information about material items recorded in the Consolidated Balance Sheets. Investments December 31, 2021 December 31, 2020 Equity method investments: Other equity method investments $ 62 $ 65 Other investments: Employee benefit trusts and investments (a) 72 61 Equity investments without readily determinable fair values 33 55 Other available for sale debt security investments 7 3 Total investments $ 174 $ 184 __________ (a) Debt and equity security investments are recorded at fair market value. Accrued expenses December 31, 2021 December 31, 2020 Compensation-related accruals (a) $ 356 $ 426 __________ (a) Primarily includes accrued payroll, bonuses and other incentives, vacation, and benefits. 23. Related Party Transactions Prior to completion of the separation on February 1, 2022, we engaged in transactions with affiliates of Exelon in the normal course of business, these affiliate transactions are summarized in the tables below. After February 1, 2022, all transactions with Exelon or its affiliates are no longer related party transactions. Operating revenues from affiliates The following table presents our Operating revenues from affiliates: For the Years Ended December 31, 2021 2020 2019 ComEd (a) $ 376 $ 330 $ 369 PECO (b) 196 190 158 BGE (c) 236 315 289 PHI 366 367 353 Pepco (d) 270 279 264 DPL (e) 79 75 70 ACE (f) 17 13 19 Other 14 9 3 Total operating revenues from affiliates $ 1,188 $ 1,211 $ 1,172 __________ (a) We have an ICC-approved RFP contract with ComEd to provide a portion of ComEd’s electricity supply requirements. We also sell RECs and ZECs to ComEd. (b) We provide electric supply to PECO under contracts executed through PECO’s competitive procurement process. In addition, we have a ten-year agreement with PECO to sell solar AECs. (c) We provide a portion of BGE’s energy requirements under its MDPSC-approved market-based SOS and gas commodity programs. 158 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 23 — Related Party Transactions (d) We provide electric supply to Pepco under contracts executed through Pepco's competitive procurement process approved by the MDPSC and DCPSC. (e) We provide a portion of DPL's energy requirements under its MDPSC and DEPSC approved market-based SOS commodity programs. (f) We provide electric supply to ACE under contracts executed through ACE's competitive procurement process. Service Company Costs for Corporate Support We received a variety of corporate support services from Exelon. Through its business services subsidiary, BSC, Exelon provided support services at cost, including legal, human resources, financial, information technology, and supply management services. The costs of BSC are directly charged or allocated to us. Certain of these services will continue after the separation and are covered by the Transition Services Agreement. See Note 24 — Separation from Exelon for additional information. The following table presents the service company costs allocated to us: Operating and maintenance from affiliates Capitalized costs For the Years Ended December 31, For the Years Ended December 31, 2021 2020 2019 2021 2020 2019 $ 588 $ 552 $ 570 $ 129 $ 54 $ 66 Current Receivables from/Payables to affiliates The following tables present Current receivables from affiliates and Current payables to affiliates: December 31, 2021 December 31, 2020 Receivables from affiliates: Payables to affiliates: Receivables from affiliates: Payables to affiliates: ComEd $ 84 $ 13 $ 78 $ 13 PECO 30 — 17 — BGE 4 — 11 — Pepco 20 — 13 — DPL 4 — 3 — ACE 7 — 6 — BSC — 102 — 72 Other 11 16 25 22 Total $ 160 $ 131 $ 153 $ 107 Noncurrent Payables to affiliates We have Noncurrent payables to ComEd and PECO as a result of the nuclear decommissioning contractual construct whereby, to the extent NDT funds are greater than the underlying ARO at the end of decommissioning, such amounts are due back to ComEd and PECO, as applicable, for payment to their respective customers. See Note 10 — Asset Retirement Obligations for additional information. The following table presents our noncurrent payables to ComEd and PECO which are recorded as noncurrent payables to affiliates: As of December 31, 2021 2020 ComEd $ 2,760 $ 2,541 PECO 597 475 159 Table of Contents Notes to Consolidated Financial Statements (Dollars in millions, unless otherwise noted) Note 24 — Separation from Exelon 24. Separation from Exelon On February 21, 2021, Exelon’s Board of Directors approved a plan to separate the competitive generation and customer-facing businesses of Constellation into a stand-alone publicly traded company (“the separation”). On February 25, 2021, Exelon filed applications with FERC, NYPSC, and NRC seeking approvals for the separation. A private letter ruling from the IRS confirming the tax-free treatment of the separation was received on September 23, 2021. Exelon received approval from FERC on August 24, 2021, and the NRC on November 16, 2021. On December 16, 2021 the NYPSC authorized the separation and accepted the terms of a Joint Proposal dated November 23, 2021, by and between Exelon, Constellation, the Staff of the New York State Department of Public Service, the New York State Office of the Attorney General, the Alliance for a Green Economy, and LIPA. The terms of the Joint Proposal, which became binding upon closing of the separation, included, among other items, specific provisions for the future retirement of our three nuclear power plant sites in New York, a $ 15 million contribution to the NDT for NMP Unit 2, and various financial assurance provisions for each unit through the completion of site restoration. See Note 10 — Asset Retirement Obligations for additional information. In order to govern the ongoing relationships between us after the separation, and to facilitate an orderly transition, we entered into several agreements with Exelon, including the following: • Separation Agreement – sets forth the principal actions to be taken in connection with the separation, including the transfer of assets and assumption of liabilities and establishes certain rights and obligations between us following the distribution • Transition Services Agreement (TSA) – governs all matters relating to the provision of services between us on a transitional basis, in addition to providing us with certain services for an expected period of two-years, provided that certain services may be longer than the term and services may be extended with approval from both parties. The services include support for information technology, accounting, finance, human resources, security, and various other administrative and operational services • Employee Matters Agreement (EMA) – addresses certain employment, compensation and benefits matters, including the allocation of employees between us and the allocation and treatment of certain assets and liabilities relating to our employees and former employees • Tax Matters Agreement - governs the respective rights, responsibilities, and obligations between us with respect to all tax matters (excluding employee related taxes covered under EMA), in addition to certain restrictions which generally prohibit us from taking or failing to take any action in the two-year period following the distribution that would prevent the distribution from qualifying as tax-free for U.S. federal income tax purposes, including limitations on our ability to pursue certain equity issuances, strategic transactions, repurchases or other transactions Pursuant to the Separation Agreement, we received a cash contribution of $ 1.75 billion from Exelon on January 31, 2022, the proceeds of which were used to settle $ 258 million of an intercompany loan from Exelon and $ 200 million of short-term debt outstanding prior to separation, in addition to a $ 192 million contribution to our pension plans. We also entered into two new five-year credit facility agreements providing $ 4.5 billion of capacity. See Note 17 — Debt and Credit Agreements and Note 15 — Retirement Benefits for additional information on these separation related items. On February 1, 2022, Exelon completed the separation through a pro-rata distribution of all of the outstanding shares of our common stock, no par value, for every three shares of Exelon common stock held on January 20, 2022, the record date of the distribution. We are now an independent, publicly traded company listed on the NASDAQ exchange under the symbol “CEG”, and regular-way trading began on February 2, 2022. Exelon no longer retains any ownership interest in CEG Parent or Constellation. Prior to completion of the separation, our financial statements include certain transactions with affiliates of Exelon, which are disclosed as related party transactions. After February 1, 2022, all transactions with Exelon or its affiliates are no longer related party transactions. See Note 23 — Related Party Transactions for additional information. 160 Table of Contents ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None.